Consolidated Federal Oil & Gas and Federal & Indian Coal Valuation Reform

Federal RegisterJul 1, 2016

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DEPARTMENT OF THE INTERIOR

Office of Natural Resources Revenue

30 CFR Parts 1202 and 1206

[Docket No. ONRR-2012-0004; DS63644000 DR2PS0000.CH7000 167D0102R2]

RIN 1012-AA13

Consolidated Federal Oil & Gas and Federal & Indian Coal Valuation Reform

AGENCY:

Office of Natural Resources Revenue (ONRR), Interior.

ACTION:

Final rule.

SUMMARY:

ONRR is amending our regulations governing valuation, for royalty purposes, of oil and gas produced from Federal onshore and offshore leases and coal produced from Federal and Indian leases. This rule also consolidates definitions for oil, gas, and coal product valuation into one subpart that is applicable to the Federal oil and gas and Federal and Indian coal subparts.

DATES:

Effective date:

January 1, 2017.

FOR FURTHER INFORMATION CONTACT:

For questions on technical issues, contact Amy Lunt at (303) 231-3746, Lisa Dawson at (303) 231-3653, Karl Wunderlich at (303) 231-3663, Chris Carey at (303) 231-3460, Megan Hessee at (303) 231-3713, Richard Adamski at (202) 513-0598, or Carrie Wallace at (303) 445-0638.

SUPPLEMENTARY INFORMATION:

I. Background

The purpose of implementing this final rule regarding the valuation of oil and gas production from Federal leases and coal production from Federal and Indian leases is (1) to offer greater simplicity, certainty, clarity, and consistency in product valuation for mineral lessees and mineral revenue recipients; (2) to ensure that Indian mineral lessors receive the maximum revenues from coal resources on their land, consistent with the Secretary's trust responsibility and lease terms; (3) to decrease industry's cost of compliance and ONRR's cost to ensure industry compliance; and (4) to provide early certainty to industry and to ONRR that companies have paid every dollar due.

Also, this final rule makes non-substantive technical or clarifying changes to the proposed rule. We re-wrote sections of the regulations in Plain Language to meet the criteria of Executive Orders 12866 and 12988 and the Presidential Memorandum of June 1, 1998, and to make our rules more clear, consistent, and readable.

II. Comments on Proposed Rule

On January 6, 2015, ONRR published a Proposed Rule to amend the valuation regulations for oil, gas, and coal produced from Federal leases and coal produced from Indian leases (80 FR 608). The proposed rule took into consideration input that we received on the Advance Notices of Proposed Rulemaking, which we published on May 27, 2011, regarding the valuation of oil, gas, and coal produced from Federal leases and coal produced from Indian leases (76 FR 30878, 30881). ONRR also considered input that we received during six public workshops that we held in September and October of 2011. The proposed rulemaking provided for a 60-day comment period, which closed on March 9, 2015. In response to over 50 stakeholder requests to extend the public comment period, we published a notice that granted a 60-day extension, which extended the comment period to May 8, 2015 (80 FR 7994). During the public comment period, we received more than 1,000 pages of written comments from over 300 commenters and over 190,000 petition signatories. We received comments from industry, industry trade groups, Congress, State governors, States, local municipalities, two Tribes, local businesses, public interest groups, and individual commenters. The petition signatories' main focus was on coal, and they aligned themselves with organizations that were either passionately against the further expansion of mining coal or were proponents of coal mining.

We carefully considered all of the public comments that we received during the rulemaking process and, in some instances, revised the language of the final rule based on these comments. We hereby adopt final regulations governing the valuation of oil, natural gas, and coal produced from Federal leases and coal produced from Indian leases. These regulations apply, prospectively, to oil, natural gas, and coal produced on or after the effective date that we have specified in the

DATES

section of this preamble.

General Comments

Because this final rule is composed of four subparts covering Federal oil and gas and Federal and Indian coal, we will organize, analyze, and respond to the comments regarding the specific subparts.

Public Comment:

All of the over 190,000 petition signatories that ONRR received during the public comment period pertained to coal. The comments and positions on coal production and values were polarized representing those supporting the coal industry and those supporting the platform highlighting green energy and coal's harm to the environment. The overwhelming majority of the signed petitions were from individuals asserting that coal production should cease and stay in the ground or that ONRR's proposed changes to coal valuation do not go far enough toward closing the perceived loopholes that the coal industry is exploiting. Many commenters who work in the coal industry or live in coal mining-dependent communities, along with one Tribe, maintain that the proposed rule goes too far. They argue that the rule imposes unwarranted valuation methods, including the “default provision,” which, they contend, hinders transparency and creates complex and subjective coal valuations. They claim that the wholesale changes to the rule would cause irreparable economic harm to the coal industry by negatively disrupting the coal market.

ONRR Response:

We appreciate the comments on both sides of the issue. The comments regarding keeping coal in the ground or regarding coal's negative impact on the socioeconomic health of communities by discouraging production, however, are beyond the scope of this rulemaking, which is limited to the valuation of coal produced from Federal and Indian leases for royalty collection purposes. We will, however, respond to the specific comments that suggested more stringent alternative valuation methods in the section-by-section analysis part of the preamble. As a general matter, many commenters have concerns about how the Federal Government leases coal, the amount of royalty charged, and whether taxpayers are getting a fair return from public resources. While this rule takes steps toward ensuring that the valuation process for Federal and Indian coal resources better reflects the changing energy industry while protecting taxpayers and Indian assets, its scope is not broad enough to address the many concerns the commenters raised. For that and other reasons, the U.S. Department of the Interior (Department) recently launched a comprehensive review to identify and evaluate potential reforms to the Ffederal coal program in order to ensure that it is properly structured to provide a fair return to taxpayers and reflect its impacts on the environment, while continuing to help meet our energy needs.

ONRR request for comments:

In the proposed rule, we solicited comments on how to simplify and improve the

valuation of coal disposed of in non-arm's-length transactions and no-sale situations. We sought input on the merits of eliminating the benchmarks for valuation of non-arm's-length sales and comments on the following questions:

• Should the royalty value of coal initially sold under non-arm's-length conditions be based on the gross proceeds received from the first arm's-length sale of that coal in situations where there is a subsequent arm's-length sale?

• If you are a coal lessee, will adoption of this methodology substantively impact your current calculation and payment of royalties on coal, and how?

• What other methods might ONRR use to determine the royalty value of coal not sold at arm's-length that we may not have considered?

Public Comment:

ONRR received only one response from an industry commenter addressing these questions. The commenter answered no to the first question and explained that valuing coal further away from the lease may not represent the true value of the coal at the lease. The commenter also added that the seller may not know who the first arm's-length purchaser may be. In response to the second question, the commenter believes that any subsequent transaction to an affiliate is not applicable to the marketability of the coal at the lease and that ONRR may or may not get a reasonable price for the valuation of the coal. The commenter responded to ONRR's third question seeking other methods by stating that ONRR should retain the benchmarks. The commenter further elaborated that the benchmarks should be reordered to 1, 4, 2, 3, and 5, plus adding a sixth benchmark (review of actual cost of production and assess a return on investment that is fair to the situation and/or the company under assessment), applicable only in those rare instances when no arm's-length sales are available.

ONRR also received several comments suggesting the option to base the value of coal on an index price.

ONRR Response:

The best indication of value is the gross proceeds received under an arm's-length contract between independent persons who are not affiliates and who have opposing economic interests regarding that contract. The best indicator of value under a non-arm's-length sale is the gross proceeds accruing to the lessee or its affiliate under the first arm's-length contract, less applicable allowances. In this final rule, we eliminated the benchmarks for both natural gas and coal. We implemented this method for Federal oil in 2000 and, in this final regulation, made it consistent for Federal gas and Federal and Indian coal.

ONRR is not currently aware of any published index prices for coal that cover a wide array of coal production that are both transparent and widely traded so as to yield a reasonable value that would represent the true market value of coal. We will monitor the coal market and may be open to considering index prices as a valuation option, if viable.

Public Comment:

ONRR received a few general comments concerning Federal oil and natural gas production. These comments fell into several categories, including natural gas measurement methods, ONRR's unbundling program, and the economic impact on the oil and gas industry.

ONRR also received general comments concerning Federal and Indian coal production. These comments fell into several categories, including the final rule's impact on coal production and the coal industry, royalty rates, and creating more transparency to the public for coal valuation.

ONRR Response:

Some of these comments were beyond the scope of the rule so ONRR did not address them specifically. We addressed other comments in the specific comment sections.

Regarding the comments on coal royalty rates, the royalty rate is a lease clause and is not a component of this final rule. Royalty rates are a part of lease negotiations, which the Bureau of Land Management (BLM), Bureau of Ocean Energy Management (BOEM), and Bureau of Indian Affairs (BIA) on behalf of the Tribes and individual Indian mineral owners conduct. The final rule does not limit or otherwise infringe on the authority of these entities to negotiate those leases. Instead, this rule is focused on ensuring that Federal and Indian mineral owners receive the royalties that are owed to them based on the value of the resources being sold and consistent with the royalty terms of the applicable leases negotiated by the BLM, BOEM and BIA.

As to comments related to increasing transparency, the U.S. Department of the Interior (Department) created a data portal as part of the Extractive Industries Transparency Initiative—a global, voluntary partnership to strengthen the accountability of natural resource revenue reporting and build public trust for the governance of these vital activities. You can access the data portal at

https://useiti.doi.gov.

A. Specific Comments on 30 CFR Part 1206—Product Valuation, Subpart A—General Provisions and Definitions

1. Definitions (§ 1206.20)

In this final rule, ONRR consolidated the definitions from Federal oil (§ 1206.101), Federal gas (§ 1206.151), Federal coal (§ 1206.251), and Indian coal (§ 1206.451). ONRR consolidated the existing definitions for these products to provide greater clarity and to eliminate redundancy. ONRR received comments on some of the modified definitions, which we discuss below.

Area:

See discussion in this preamble under § 1206.105 regarding the definition of the term “area.”

Coal Cooperatives:

ONRR added a new definition of the term “

coal cooperatives

” that defines formal or informal organizations of companies or other entities sharing in a common interest to produce and market coal or coal-based products, the latter generally being electricity.

Public Comment:

One commenter argued that defining a coal cooperative was unnecessary. The commenter suggested that contracts are either arm's-length or non-arm's-length and that it does not matter if affiliated parties are part of a corporation or an ONRR-defined cooperative.

ONRR Response:

We seek a clear, consistent, and repeatable standard for valuing coal at its true market value. Coal cooperatives are formal or informal organizations of companies or other entities sharing in a common interest to produce and market coal or coal-based products, the latter generally being electricity. The services and benefits that coal cooperatives provide include, but are not limited to, manufacturing, selling, sampling, storing, supplying, permitting, transporting, marketing, or other logistic services. The relationship between a coal cooperative's members is not one of “opposing economic interests” and, therefore, is not at arm's-length.

If none of the members own 10 percent or more of the coal cooperative, the coal cooperative will not be an affiliate under the definitions in this rule found in § 1206.20. Nevertheless, the relationship between the coal cooperative and its members, as well as between the coal cooperative's members, is not at arm's-length for valuation purposes because they lack opposing economic interests. Therefore, the lessee must base the value of its coal production on the first arm's-length sale price received for the coal or electricity. We retained the term “

coal cooperative,

” but, in light of the

comment that we received, we changed the proposed definition.

Gathering:

In this final rule, any movement of bulk production from the wellhead to a platform offshore is gathering and not transportation. ONRR changed the definition of the term “

gathering

” and added paragraph (a)(1)(ii) in §§ 1206.110 and 1206.152 to rescind the May 20, 1999, “Guidance for Determining Transportation Allowances for Production from Leases in Water Depths Greater Than 200 Meters” (Deep Water Policy). The Deep Water Policy allowed lessees to deduct certain costs associated with moving bulk production from the seafloor to the first platform.

Public Comment:

ONRR received several comments from industry and industry trade groups opposing our proposal to rescind the Deep Water Policy. Generally, the commenters opposed the categorical exclusion of subsea movement costs prior to the first platform as a transportation allowance. The commenters argued that such a determination was arbitrary and capricious. The commenters stated that rescinding the Deep Water Policy penalizes the development of innovative technologies that minimize surface facilities, reduce environmental risks, and increase ultimate recovery. Commenters stated that ONRR previously identified the movement of bulk production to the first platform as a valid transportation deduction and argue that we are now failing to provide sufficient justification to warrant rescinding the Deep Water Policy.

ONRR received comments from public interest groups and a State supporting the removal of the Deep Water Policy. These commenters argued that the Deep Water Policy was inconsistent with ONRR's definition of gathering, and rescinding the policy will cure improper deductions of subsea gathering costs. In addition, the commenters believe that the proposed change will assure a fair market value for production while also reducing administrative costs for the oil and gas industry.

ONRR Response:

The former Minerals Management Service intended for the Deep Water Policy to incentivize deep water leasing by allowing lessees to deduct broader transportation costs than the regulations allowed. ONRR concluded that the Deep Water Policy has served its purpose and is no longer necessary. The regulations still allow offshore lessees to deduct considerable transportation costs to move oil and gas from the offshore platform to onshore markets. Rescinding this policy clarifies the meaning of gathering, which, in turn, provides a more consistent and reliable application of the regulations.

Public Comment:

ONRR received comments stating it understated the cost estimate of the impact to industry from removing the Deep Water Policy. The commenters claim the cost of removing the Deep Water Policy is much higher than ONRR's estimated $17.4 to $23.6 million total annual loss to all of industry.

ONRR Response:

ONRR does not agree. ONRR estimated the costs to industry using actual costs industry provided to ONRR during audits of the subsea gathering pipelines. ONRR used this data to estimate a per mile cost for subsea gathering pipelines. ONRR then used this per mile cost to calculate the total burden on industry associated with eliminating the Deep Water Policy. ONRR stands by its analysis.

Misconduct:

ONRR added a new definition for the term “

misconduct.

” This new definition will apply to—and in conjunction with the—default provision. Misconduct, in this subpart, is different than—and in addition to—any violations subject to civil penalties under the Federal Oil and Gas Royalty Management Act of 1982 (FOGRMA), 30 U.S.C. 1719, and its implementing regulations in 30 CFR part 1241. Behavior that constitutes misconduct under part 1206 does not need to be willful, knowing, voluntary, or intentional. This is a valuation mechanism, not an enforcement tool.

Public Comment:

Industry claims that the definition of misconduct is overly broad and argues that any common understanding of misconduct implies an element of intentional wrongdoing. Industry fears that ONRR may expand the use of the term to include even minor occurrences, such as simple reporting errors.

ONRR Response:

According to

Black's Law Dictionary,

the term “

misconduct

” is “any failure to perform a duty owed to the United States under a statute, regulation, or lease, or unlawful or improper behavior, regardless of the mental state of the lessee or any individual employed by, or associated with, the lessee.” Consistent with this definition, this final rule does not require behavior to be willful, knowing, voluntary, or intentional to constitute misconduct. We only intend to use this definition of the term “

misconduct

” for valuation purposes, not for imposing penalties. Thus, no intent is required. Moreover, FOGRMA does not mandate a particular mental state for a lessee's obligation to correctly report, account for, and pay royalties for purposes of royalty valuation. For example, under this final rule, if we determine that you improperly calculated the value of your gas due to misconduct, we will calculate the value of your gas under § 1206.144. However, if we determine that the misconduct was knowing or willful, we may pursue civil penalties under 30 CFR part 1241.

B. Specific Comments on 30 CFR Part 1206—Product Valuation, Subpart C—Federal Oil

1. Calculating Royalty Value for Oil Sold Under an Arm's-Length Contract (§ 1206.101)

Default:

ONRR added that the value in this paragraph does not apply if we decide to value your oil under its new default valuation provision, which allows us to value your oil production under § 1206.105 or any other provision in this subpart. We also added that we may decide a lessee's oil value under the default valuation provision if the lessee fails to make the election in this paragraph related to exchange agreements.

Public Comment:

Almost unanimously, industry commenters object to the use of ONRR's default provision for oil. Industry comments highlight the following concerns: “standardless” ONRR discretion, second-guessing of arm's-length contracts and other lessee valuations, and a denial of lessees' ability to deduct all appropriate costs to reflect value at the lease. Several industry commenters argued against ONRR's ability to determine royalty value when a lessee or designee sells oil or gas for ten percent less than the lowest reasonable measures of market value. The industry commenters claim that different companies can negotiate better prices than others based on size and bargaining power.

Several industry trade groups stated that it is not clear which offices (audit and compliance, enforcement, valuation, etc.) within ONRR have the ability to invoke the default provision and question whether there would be consistency in its application. These industry commenters also believe that the default provision (1) does not allow ONRR to honor arm's-length contracts and gross proceeds as the basis of valuation as in the past; (2) lacks specific criteria for determining what is reasonable valuation; (3) ONRR should not use it for simple reporting errors; and (4) is burdensome, an overreach of valuation authority, and creates uncertainty. Several industry trade groups add that the proposed rule offers little more than “

raw ipse dixit

” for promulgating its default provision and how ONRR intends to use it.

Several public interest groups suggested that the default provision should be mandatory and not discretionary. The consolidated comments from the State and Tribal Royalty Audit Committee (STRAC) provide that the State or Tribe must grant approval if ONRR applies the default provision in their jurisdiction.

ONRR Response:

ONRR disagrees with the commenters' statements that the default provision is a radical departure from our previous valuation policy. The regulatory changes do not alter the underlying principles of the previous regulations. For example, nothing in this final rule changes the Department's requirement that, for purposes of determining royalty, the value of crude oil produced from Federal leases is determined at or near the lease. And nothing in this final rule changes the fact that gross proceeds from arm's-length contracts are the best indication of market value.

The default provision addresses valuation situations where circumstances result in the Secretary of the Interior's (Secretary) inability to reasonably determine the correct value of production. Such circumstances include, but are not limited to, the lessee's failure to provide documents, the lessee's misconduct, the lessee's breach of the duty to market, or any other situation that significantly compromises the Secretary's ability to reasonably determine the correct value. The mineral statutes and lease terms give the Secretary the authority and considerable discretion to establish the reasonable value of production by using a variety of discretionary factors and any other information that the Secretary determines is relevant. The default provision simply codifies the Secretary's authority to determine the value of production for royalty purposes and specifically enumerates when, where, and how the Secretary will use that discretion.

Under this final rule, ONRR will continue the same treatment of arm's-length contracts as we have historically. We have never tacitly accepted values received under arm's-length contracts. We analyze all types of sales contracts in our reviews in order to validate proper value and deductions.

Some commenters contend that ONRR did not perform an adequate economic analysis in assigning a royalty impact to invoking the default provision. We disagree and emphasize, again, that we anticipate using the default provision only in very specific cases where we cannot determine proper royalty values through standard procedures. Moreover, the royalty impact will be relatively small because the default provision will always establish a reasonable value of production using market-based transaction data, which has always been the basis for our royalty valuation rules.

ONRR considers a lessee's refusal to provide requested documents to be a failure to permit an audit that is, and will continue to be, subject to civil penalties. ONRR's choice to invoke the default provision will not impact the lessee's obligation to provide documents or ONRR's ability to assess civil penalties for failure to permit an audit.

Some commenters stated that it is not clear which offices within ONRR will apply the default provision and, if they did, what valuation criteria they would employ. We anticipate that, in most cases, we will use the default provision during the course of an audit. And, as we stated, the criteria that we would use to establish a royalty value is the same basic criteria upon which we base all royalty values. We list these criteria in § 1206.105(a)-(f). Specifically, we may consider the value of like-quality oil in the same field or nearby fields or areas; the value of like-quality oil from the same plant or area; public sources of price or market information that we deem to be reliable; information available and reported to us, including, but not limited to, on the Report of Sales and Royalty Remittance (Form ONRR-2014) and the Oil and Gas Operations Report (Form ONRR-4054); costs of transportation, if we determine that they are applicable; or any information that we deem relevant regarding the particular lease operation or the salability of the oil.

Some industry commenters expressed concerns over their ability to challenge our use of the default provision. Industry's concerns are unwarranted because a company may appeal an order, including an order wherein we used the default provision to determine royalty value. Appeal rights under 30 CFR part 1290 will not change under this final rule.

We disagree with those commenters who sought to make the default provision mandatory. We reiterate that we intend to use the default provision only in specific cases where conventional valuation procedures have not worked to establish a value for royalty purposes. We have the authority to use the default provision on behalf of the Secretary and as part of our delegated or cooperative agreements. We will work with STRAC to determine the royalty value of production that occurs in an affected State or on Tribal lands.

2. Calculating Royalty Value for Oil Not Sold Under an Arm's-Length Contract (§ 1206.102)

Default:

ONRR added a default valuation provision that allows us to value your oil production under § 1206.105 or any other provision in this subpart. We addressed comments pertaining to the “Default Provision” paragraph, which we detail in § 1206.101, in this Preamble.

3. Determination of Correct Royalty Payments (§ 1206.104)

Default:

Misconduct:

ONRR added a new definition for the term “

misconduct.

” We addressed comments pertaining to this definition, which we detail in § 1206.20, in this Preamble.

Unreasonably high transportation cost:

ONRR added a default provision allowing us to determine your transportation allowance under § 1206.105 if (1) there is misconduct by or between the contracting parties; (2) the total consideration that you or your affiliate pays under an arm's-length contract does not reflect the reasonable cost of transportation because you breached a duty to market oil for the mutual benefit of the lessee and the lessor by transporting oil at a cost that is unreasonably high; or (3) ONRR cannot determine if you properly calculated a transportation allowance for any reason. We addressed the default provision in detail in § 1206.101.

Public Comment:

Many of the comments from industry and industry trade groups regarding our potential use of the default provision as it relates to the transportation of oil mirror those put forth for determining the value of oil. Commenters believe that our use of a 10-percent variance above the highest reasonable measure of transportation standard is arbitrary, capricious, and unnecessary. Some comments representing States' interests, however, believe that ONRR should include stronger regulatory language requiring us to use the default method when the 10-percent variance is reached.

ONRR Response:

The default provision is an accommodating and necessary valuation tool that allows the Secretary to determine the correct amount of transportation deductions for oil. The 10-percent variance that we

may

use in our analysis of

transportation transactions is nothing more than a tolerance to help determine a proper transportation allowance. In past and current compliance reviews and audit procedures, we have always used tolerances to reflect what is reasonable in any given market at any given time. Our use of the default provision under the final valuation regulations is a continuation of current practice. We will continue to determine transportation costs that industry incurs on their own merits based on reasonable actual costs allowable under the regulations.

Written contracts:

In this final rule, a lessee or its affiliate must have all of its contracts, contract revisions, or amendments in writing and signed by all the parties to those contracts, revisions, or amendments. Where the lessee does not have a written contract, ONRR may use the default provision to determine value.

Public Comment:

We received multiple comments on the rule's new provision stating that we will determine transportation allowances under § 1206.105 if lessees do not have a written contract. The commenters generally disagreed with our requirement that all contracts be in writing because such a requirement is inconsistent with industry contracting procedures. Commenters also noted that contracts that are not in writing are still enforceable and that ONRR's definition of a contract in § 1206.20 includes oral contracts that are legally enforceable.

ONRR Response:

FOGRMA requires the Secretary to “establish a comprehensive inspection, collection and fiscal and production accounting and auditing system to provide the capability to accurately determine oil and gas royalties . . . and to collect and account for such amounts in a timely manner.” 30 U.S.C. 1711(a). FOGRMA also requires lessees to provide “any information the Secretary, by rule, may reasonably require” 30 U.S.C. 1703(a). Since adopting the regulations in 1988, ONRR has required lessees to value their oil and gas production based on the gross proceeds accruing to the lessees for the sale of that oil and gas. These gross proceeds include deductions for the lessees' reasonable and actual costs of transportation. When lessees calculate their gross proceeds that include arm's-length sales and arm's-length transportation costs, the lessees must use the terms of those arm's-length contracts to calculate their gross proceeds. We have the responsibility of auditing gross proceeds in order to ensure that they reflect the total consideration actually transferred, either directly or indirectly, from the buyer to the seller. Through this auditing process, we have found it difficult to verify the accuracy of lessees' royalty payments when the lessees enter into oral contracts.

This final rule's requirement that all arm's-length contracts be in writing is a logical evolution of our previous regulations. Section 1207.5 requires lessees to commit oral contracts to written form and keep them as records. And the previous rules required arm's-length sales contract revisions and amendments to be in writing and signed by all parties. For more information about this,

see

§§ 1206.153(j), 1206.52(d)(2), 1206.102(e)(2)(ii) (requiring any amendment or revision to arm's-length purchase prices for oil to be in writing and signed by all parties in the agreement). By requiring fully-executed arm's-length contracts, we no longer rely just on the lessee's written documentation outlining the terms of oral contracts. This guarantees that we can verify that the lessee's gross proceeds calculations are correct and include all consideration that you documented in the contract.

One commenter provided case law indicating that contracts do not have to be in writing to be enforceable. This comment, however, ignores the burden that we bear to verify and accurately determine that the lessees' royalty payments are correct. We must audit and evaluate countless contracts in order to verify royalty payments for Federal and Indian lands. Tracking email exchanges, letters, or other confirmations creates inefficiencies in our accounting and auditing systems, which limits our ability to fulfill FOGRMA's mandate to verify and account for royalty payments.

4. Determination of the Oil Value for Royalty Purposes (§ 1206.105)

Default:

Area:

ONRR removes the phrase “legal characteristics” from the definition of the term “

area.

”

Public Comment:

We received comments from industry that they oppose the modified definition of “area.” The commenters believe that the new definition would “revise the definition of area in a manner that overtly changes the breadth of the marketable condition rule.” The commenters rely on the Interior Board of Land Appeals' (IBLA) decision in

Encana Oil & Gas (USA), Inc.,

185 IBLA 133 (2014) (

Encana

) as an example to illustrate how the definition of area has expanded over time. One commenter stated, “In short, the ONRR's proposed revision of the definition of `area' will result in inconsistent and uncertain marketable condition determinations.”

ONRR Response:

We modified the definition of the term “

area

” to clarify that an area does not have boundaries or names. The commenter's concern, however, is misplaced because the definition of the term “

marketable condition

” remains the same. And, as the commenter points out, case law aids in defining the term “

marketable condition.

” We cite

Encana

as the basis for this, where the finding was that a “sales contract typical for the field or area” reasonably refers to the contracts that are typical in the field or area into which the gas is actually sold, which may or may not be the field or area where the gas is produced. Because we do not change the definition of the term “

marketable condition

” and our modification to the term “

area

” does not alter the precedent set out in

Encana

and other cases interpreting the definition of the term “

marketable condition,

” we are retaining the definition of the term “

area

” as we have proposed.

5. Valuation Determination Requests (§ 1206.108)

Guidance and Determinations:

Under paragraph (a), a lessee may request a valuation determination or guidance from ONRR regarding any oil produced. Paragraph (a) provides that the lessee's request for a determination must (1) be in writing; (2) identify all leases involved; (3) identify all interest owners in the leases; (4) identify the operator(s) for those leases; and (5) explain all relevant facts. In addition, under paragraph (a), a lessee must provide (1) all relevant documents; (2) its analysis of the issue(s); (3) citations to all relevant precedents (including adverse precedents); and (4) its proposed valuation method.

In response to a lessee's request for a determination, ONRR may (1) decide that we will issue guidance; (2) inform the lessee in writing that we will not provide a determination or guidance; or (3) request that the Assistant Secretary for Policy, Management and Budget (ASPMB) issue a determination.

Paragraphs (b)(3)(i) and (ii) identify situations in which ONRR and the Assistant Secretary typically do not provide a determination or guidance, including, but not limited to, requests for determinations or guidance on hypothetical situations and matters that

are the subject of pending litigation or administrative appeals.

Under paragraph (c)(1), a determination that the ASPMB signs binds both the lessee and ONRR unless the Assistant Secretary modifies or rescinds the determination.

Public Comment:

Industry raised three concerns regarding valuation guidance and determinations. First, commenters were concerned that ONRR will require excessive data and legal analysis in order for industry to receive valuation guidance or a determination. Second, commenters suggest that ONRR add language specifying that, if a lessee receives non-binding guidance and then chooses not to follow that guidance, ONRR would not pursue civil penalties based on that guidance. Third, commenters suggest that ONRR provide only appealable determinations and binding determinations that the ASPMB signs rather than non-appealable, non-binding guidance.

ONRR Response:

In this final rule, we retained the language requiring industry to provide specified information to receive a valuation determination. However, we recognize that, where a lessee requests valuation guidance rather than a determination, less information may suffice because requests for guidance are not requests for our approval of a valuation method.

Under 30 CFR part 1241, ONRR may issue a notice of non-compliance if you fail to comply with any requirement of a statute, regulation, order, or terms of a lease. Because this language clearly establishes when we may issue a notice of non-compliance, it is not necessary to add language specifically addressing civil penalties for failure to follow non-binding guidance.

We provide guidance in cases where industry has a question regarding the application of statutes and regulations to a particular set of circumstances. This guidance provides industry with an opportunity to ask questions about their particular circumstances without proposing a valuation method. Requests for determinations, on the other hand, are proposals from industry for ONRR approval of a specific valuation method. By providing a guidance option, we can answer questions more quickly and without requiring industry to submit all of the information that we would require for a determination. Industry may always request a binding determination.

6. General Transportation Allowance Requirements (§ 1206.110)

In this final rule, we re-ordered paragraph (a) to add clarity.

Subsea gathering:

In paragraph (a), we added a new provision stating that you may not take a transportation allowance for the movement of oil produced on the Outer Continental Shelf (OCS) from the wellhead to the first platform. This addition, along with the changes to the definition of gathering, rescinds the Deep Water Policy. We addressed comments pertaining to this issue in § 1206.20.

Fifty-percent allowance cap:

In this final rule, we eliminated the regulation allowing us to approve transportation allowances in excess of 50 percent of the value of a lessee's oil production. Under this final rule, any prior approvals terminate on the date when this rule becomes final.

Public Comment:

We received comments from States and public interest groups supporting the elimination of ONRR's authority to approve transportation allowances in excess of the 50-percent allowance cap. However, the State commenters asserted that the 50-percent cap, itself, was too broad. The States suggested that we calculate allowance caps for each State and use a percentage based on the average transportation costs in each State over a ten-year period. The State commenters suggested that we update and post such percentages on our Web page.

ONRR Response:

At this time, we decline to implement the States' suggestion to reevaluate caps on transportation allowances as a whole. The 50-percent limitation is not the only check on the reasonableness of transportation costs. The 50-percent limitation supplements the requirement that a lessee's transportation costs be actual and reasonable. In this final rule, the limitation clause states that your transportation allowance may not exceed 50 percent of the oil value determined under § 1206.101. This final rule defines the term “

transportation allowance

” as a deduction in determining royalty value for reasonable, actual costs that the lessee incurs for moving oil to a point of sale or delivery off of the lease. The 50-percent limitation is a limit on the allowance—a lessee's reasonable, actual costs of transportation—and not a statement that any cost up to 50 percent is reasonable. To find otherwise would allow a lessee to spend $100 on a repair that could have been performed for $10 and deduct the entirety of the expense against a $200 royalty obligation. Thus, the regulation, read as a whole, mitigates the States' concern.

Public Comment:

ONRR received several comments from industry and industry trade groups opposing the elimination of our authority to approve transportation allowances in excess of the 50-percent allowance cap. These commenters stated that the right to request approval to exceed the 50-percent limitation is necessary because its removal denies a lessee the ability to deduct all of its actual, reasonable, and necessary transportation costs when those costs exceed 50 percent.

ONRR Response:

The 50-percent limitation is a sufficient transportation allowance. The Mineral Leasing Act (MLA) requires lessees to pay royalties at 12

1/2

percent in amount or value of production removed or sold from the leased lands. The Outer Continental Shelf Lands Act (OSCLA) requires a royalty of not less than 12

1/2

percent in amount or value of production saved, removed, or sold from the leases. However, the MLA and OCSLA do not define the term “

value,

” which gives the Secretary considerable discretion to define the term “

value.

” The regulations at 30 CFR part 1206 determine value and, under these regulations, the Secretary allowed deductions for transportation allowances. It is this discretion that provides an allowance, generally, which the Secretary now caps at 50 percent of the value of oil production.

Public Comment:

Several commenters take issue with ONRR terminating any approval that it previously issued for a lessee to exceed the 50-percent limitation. The commenters believe that terminating prior approvals is “retroactive.” Thus, the commenters suggest that ONRR should allow such approval to expire on the expiration date set out in the approval.

ONRR Response:

We disagree with the commenters who claim that the proposed rule's termination of prior approvals to allow transportation allowances to exceed the value of a lessee's oil production is retroactive. In

Reynolds

United States,

292 U.S. 443, 449 (1934), the Supreme Court determined that “a statute is not rendered retroactive merely because the facts or requisites upon which it's subsequent action depends, or some of them, are drawn from a time antecedent to the enactment.” This means, as long as the new rule does not modify “the

past

legal consequences of past actions,” those rules are not improperly retroactive.

Bowen

Georgetown Univ. Hosp.,

488 U.S. 204, 219-20 (1988) (J. Scalia, concurring). Just because an agency's rule may “upset[ ] expectations based on prior law” does not mean the rule is retroactive.

Mobile Relay Associates

F.C.C.,

457 F.3d 1, 10-11 (D.C. Cir. 2006).

While terminating prior approvals to exceed the 50-percent cap for transportation allowances may disappoint some lessee's expectations, the rule, itself, is not retroactive because it does not affect the legal consequences of the lessee's past actions. Prior to this final rule, under our approval, a lessee was able to deduct transportation allowances that were higher than 50 percent of the value of the lessee's oil production. The new rule does not hinder the lessee's ability to do so for past production months; however, for each production month after the effective date of this rule, a lessee will no longer be able to deduct over 50 percent of the value of its oil production as a transportation allowance. Thus, this final rule is entirely prospective and not, as the opposing comments suggest, retroactive.

ONRR approved most requests to exceed the 50-percent cap on transportation allowances for a one-year period. Rarely, we approved them for a two-year period. In either case, the proposed rule put lessees on notice that we intended to remove such approvals.

Public Comment:

A few commenters also state that, because ONRR retained a similar provision in the new Indian oil valuation amendments, removing that provision here would be arbitrary.

ONRR Response:

While we retained the provision in the Indian oil valuation amendments, we have never received a request to exceed the 50-percent limitation on transportation allowances for Indian oil. And, unlike with this rule, the purpose of the Indian oil valuation amendments was to implement recommendations from a negotiated rulemaking committee. Because the committee did not recommend a change, we retained this provision. We may revisit the issue of a cap on transportation allowances claimed on Indian oil at a later date.

Eliminating transportation factors:

Previously, ONRR allowed lessees to net transportation from their gross proceeds when the lessees' arm's-length contract reduced the price of the oil by a transportation factor. In this final rule, we eliminated this provision and, instead, require lessees to report such costs as a separate entry on Form ONRR-2014.

Public Comment:

ONRR received comments from industry, industry trade groups, and an individual commenter opposing the elimination of transportation factors. The commenters stated that, if ONRR eliminated transportation factors, it would result in numerous complications due to insufficient guidance.

One industry trade group pointed out that ONRR does not define the term “

transportation factor

” in the proposed rule, and it is, therefore, unclear what is or is not a transportation factor. They suggest that, if ONRR pursues not allowing the netting of the transportation factor, ONRR needs to clearly define the term.

The commenters also noted that lessees will have a difficult time discerning what a transportation factor is because the lessees do not incur the costs, their purchasers do. Therefore, the commenters claim that the detail of the costs is not readily available to lessees to accommodate reporting the costs separately as transportation allowances. One commenter stated that transportation factors may include multiple items, “some of which may not be considered a transportation factor.”

ONRR Response:

In this final rule, lessees may deduct their reasonable actual costs of transportation. The burden lies with the lessees to support their reasonable actual costs of transportation. We have never defined the term “

transportation factor.

” Historically, we used the term “

transportation factor

” to identify the situation when a sales contract contains a provision to reduce the base price by costs that the purchaser incurred to move the production to a downstream location.

These comments underscore why we eliminated transportation factors: To facilitate transparency, audits, and reviews. Eliminating factors ensures that transportation allowances are measurable and auditable because we can identify and audit transportation deductions when lessees report them separately from their sales price. When lessees report their sales value net of transportation, we cannot discern the transportation costs from the sales value. Moreover, the comment stating that transportation factors include multiple other items, including quality differences and services that may not be deductible from the royalty basis, shows the difficulty that we face in reviewing transportation factors as allowable transportation deductions. The factors may include bundled costs or may be a differential. Yet lessees, not ONRR, have the burden of identifying their allowable, reasonable, and actual costs of transportation. Eliminating transportation factors and requiring lessees to report transportation separately as allowances ensures that lessees meet that burden.

Misconduct:

ONRR added a new definition for the term “

misconduct.

” We addressed comments pertaining to this issue, which we detail in § 1206.20, in this Preamble.

Default:

ONRR addressed comments pertaining to the “Default Provision” paragraph, which we detail in § 1206.101, in this Preamble.

Unreasonably high transportation cost:

ONRR addressed comments pertaining to this issue, which we detail in § 1206.104, in this Preamble.

7. Determination of Transportation Allowances for Arm's-Length Transportation (§ 1206.111)

Line fill:

ONRR retains the provision allowing a lessee to include the costs of carrying line fill on its books as a component of arm's-length transportation allowances. We deleted proposed § 1206.111(c)(9) and retained line fill as an allowable deduction in the final rule as the new § 1206.111(b)(11). Because oil will only flow through a pipeline if that pipeline is filled with oil, some pipeline operators require that shippers (lessees) leave some of their oil in the pipeline. The shipper's oil that remains in the pipeline is, in effect, inventory that cannot be sold as long as the shipper uses the pipeline to transport its oil. In other cases, the pipeline operator owns the oil that fills the line and charges the shipper a cost at least equal to its capitalized costs as part of the arm's-length price or tariff. We proposed to eliminate this provision because we considered this to be a cost of marketing the oil, reasoning that line fill occurs after the royalty measurement point and is necessary in order for the pipeline operator to transport Federal oil production to downstream markets. We requested comments on whether line fill is a marketing cost.

Public Comment:

ONRR received several comments on line fill. Industry pointed out that, in the 2004 Federal Oil Valuation Rule, ONRR identified line fill as a cost of transportation. In that same rulemaking, ONRR also pointed out that they do not allow a lessee to deduct the costs of marketing. At that time, ONRR recognized that line fill is not a marketing cost. Industry believes that line fill is not a cost of marketing oil. Instead, industry believes that, in cases where the pipeline requires it to dedicate its oil to transport its oil, ONRR should permit the cost of carrying this inventory as an allowable transportation deduction.

A public interest group supported the change and believes that the removal of this provision is in keeping with the overall goal of achieving a fair return for the taxpayer. One State agreed with ONRR's proposal, noting that line fill falls within a lessee's duty to market.

ONRR Response:

We agree with industry commenters that lessees may deduct their reasonable actual transportation costs. For those lessees who must provide production as line fill, we retained the provision that allows the cost of carrying on your books as inventory a volume of oil that you or your affiliate, as the pipeline operator, maintain(s) in the line as line fill as an allowable transportation cost.

Written contracts:

We added a new provision that states that we will determine transportation allowances under § 1206.105 if lessees do not have a written contract for the arm's-length transportation of oil. We addressed comments pertaining to this issue, which we detail in § 1206.104, in this Preamble.

Eliminating transportation factors:

8. Determination of Transportation Allowances for Non-Arm's-Length Transportation Contracts (§ 1206.112)

Line fill:

ONRR retains the provision that allows lessees to include the costs of carrying line fill on their books as a component of arm's-length transportation allowances. We deleted proposed § 1206.111(c)(9) and retained line fill as an allowable deduction in the final rule as the new § 1206.112(c)(1)(v). We proposed to eliminate this provision because we considered this a cost of marketing the oil, reasoning that line fill occurs after the royalty measurement point and is necessary in order for the pipeline operator to transport Federal oil production to downstream markets. We requested comments on whether line fill is a marketing cost. We addressed comments pertaining to this issue, which we detail in § 1206.110, in this Preamble.

Pipeline losses:

In this final rule, under paragraph (c)(2)(ii), ONRR eliminated the provision that allows lessees to deduct the costs of pipeline losses, both actual and theoretical, under non-arm's-length transportation situations.

Public Comment:

Multiple companies and industry trade groups opposed removing the provision to allow lessees with non-arm's-length transportation arrangements to deduct actual and theoretical losses, stating that losses are a real cost to lessees.

A State commenter supported this change and suggested disallowing all losses, including line loss charges under arm's-length contracts. A public interest group supported this change, stating that this change will ensure that royalty value is based on oil actually removed from the lease without subsidizing losses occurring after the royalty measurement point.

ONRR Response:

Beginning with the May 5, 2004, Federal Oil Valuation Rule, we allowed lessees to deduct the costs of actual line losses in non-arm's-length oil transportation situations. Since that time, it has been difficult for lessees to demonstrate, and impractical for us to verify, that line losses in non-arm's-length or no-contract situations are valid and not the result of meter error or other difficult-to-measure causes.

BBB bond rate:

ONRR reduced the multiplier on any remaining undepreciated capital costs from 1.3 to 1.0 times the Standard & Poor's BBB bond rate. We moved this provision to § 1206.112(i)(3).

Public Comment:

Several companies and industry trade groups opposed modifying the Standard & Poor's BBB bond rate multiplier. Commenters state that ONRR failed to sufficiently analyze rates of return for pipelines and should provide better support for its decision to reduce the multiplier to 1.0. A State supported reducing the multiplier, noting that market fluctuations impact transportation facilities less.

ONRR Response:

Modifying the Standard & Poor's BBB bond rate multiplier recognizes changes within the economy since 2005 (including lower interest rates) and creates consistency with other product valuation guidelines. This rate better reflects the cost of borrowing to finance capital expenditures involved in pipeline construction.

9. Adjustments and Transportation Allowances When Using NYMEX Prices or Alaska North Slope (ANS) Prices for Oil Royalty Value (§ 1206.113)

Eliminating transportation factors:

10. Reporting Requirements for Arm's-Length Transportation Contracts (§ 1206.115)

Eliminating transportation factors:

Eliminating transportation factors will require lessees to report any transportation costs embedded in an arm's-length contract as a separate line entry on Form ONRR-2014.

Public Comment:

ONRR received multiple comments indicating industry would suffer significant administrative burdens to extract, separate or “unbundle” transportation costs from their arm's-length sales contracts. The commenters indicated that removing transportation factors will result in “large scale contract review and major changes to accounting systems and processes.”

ONRR Response:

We recognize that eliminating transportation factors requires lessees to report their transportation costs embedded in an arm's-length contract separately as a transportation allowance, which may require changes in the lessees' reporting systems. However, removing transportation factors increases transparency and helps us verify that such costs are the reasonable and actual costs that lessees incur for transportation. Furthermore, as we mentioned previously, transportation factors may include multiple items embedded in arm's-length sales contracts.

C. Specific Comments on 30 CFR Part 1206—Product Valuation, Subpart D—Federal Gas

1. Calculating Royalty Value for Unprocessed Gas Sold Under an Arm's-Length or Non-Arm's-Length Contract (§ 1206.141)

Dual accounting:

Because we removed the dual accounting requirement under proposed § 1206.151, we deleted paragraph (a)(3), which referenced it. We re-numbered proposed paragraph (a)(4) as (a)(3) in this final rule.

First arm's-length sale:

In this final rule, ONRR eliminated the non-arm's-length valuation benchmarks and requires lessees to value gas production based on how they sell their gas (

such as

using (1) the first arm's-length-sale prices, (2) optional index prices, or (3) volume weighted average of the values established under this paragraph for each contract for the sale of gas produced from that lease). Under § 1206.141(b)(2), if you sell or transfer your Federal gas production to your affiliate, or some other person at less than arm's-length, and that person or their affiliate then sells the gas at arm's-length, you will base your royalty value on the other person's (or their affiliate's) gross proceeds under the first arm's-length contract. However, two exceptions apply: (1) Lessees may elect to use the index-pricing option under § 1206.141(c) of this section, or (2) we decide to value your gas under the default valuation provision in § 1206.144.

Public Comment:

A State and a public interest group supported ONRR's proposal to require lessees to value non-arm's-length dispositions of gas production based on the first arm's-length sale rather than the gas valuation benchmarks.

Industry trade groups suggested that ONRR reword the regulatory language under subsection (b) for clarity. The commenters were concerned that the word “may” and the words “or another person,” could lead to misinterpretation of this rule's intent.

ONRR Response:

We recognize that the wording under proposed § 1206.141(b) caused some confusion and reworded this paragraph in the final rule.

Public Comment:

Several industry commenters asserted that tracing their affiliates' arm's-length gross proceeds is complicated and burdensome. One industry trade group remarked that § 1206.141(b) does not address costs unique to marketing and transporting Compressed Natural Gas (CNG) and Liquefied Natural Gas (LNG), where the first arm's-length sale may be at a distant international market.

ONRR Response:

The values established in arm's-length transactions are the best indication of market value. We recognize that changes in industry and the marketplace may make it difficult for a lessee to value its gas using the benchmarks. To address these difficulties, we eliminated the benchmarks in order to provide early certainty and gave lessees with non-arm's-length sales the option to value gas based on the first arm's-length sale or index prices.

Index-based valuation option:

ONRR added a new paragraph (c) containing an index-price valuation method that a lessee may elect to use in lieu of valuing its gas under proposed paragraphs (b)(2) and (b)(3). ONRR based the method on publicly-available index prices, less a specified deduction to account for processing and transportation costs. This valuation method also applies to certain “no contract” situations that we describe under paragraph (e).

The index-based option provides a lessee with a valuation option that is simple, certain, and avoids the requirements to unbundle fees and “trace” production. This is applicable when there are numerous non-arm's-length sales prior to an arm's-length sale. Under paragraph (c), the lessee may choose to value its gas only in an area that has an active index pricing point published in an ONRR-approved publication. The lessee may elect to value its gas under this paragraph, making that election binding on the lessee for two years. ONRR will post a list of approved publications at

www.onrr.gov.

In this final rule, under paragraph (c), there are three possible scenarios for establishing the index-price point. The first scenario is when you can only transport gas to one index pricing point published in an ONRR-approved publication. In this scenario, your value for royalty purposes is based on that index pricing point.

The second scenario is when you can physically transport gas to more than one index pricing point. In this scenario, you must base your value for royalty purposes on the highest index pricing point to which your gas could flow. For example, assume that you have a lease in the West Delta area of the Gulf of Mexico, and your lease is physically connected by a pipeline to the Mississippi Canyon Pipeline. In this case, your gas is physically capable of flowing to the Toca Plant (through the Southern Natural Gas Pipeline), the Yscloskey Plant (through the Tennessee Gas Pipeline), or the Venice Plant. This means that you have multiple index pricing points to which your gas can physically flow. Also, assume that the highest reported monthly bidweek price among the multiple index pricing points is the Tennessee Gas 500 Leg Price at the tailgate of the Yscloskey Plant. Finally, assume that you cannot flow your gas through the Tennessee Gas Pipeline (to the Yscloskey Plant) because all available capacity on that pipeline is under contract to other persons, and the pipeline has no capacity available to you for the production month—in other words, it is constrained. In this example, you would use the highest reported monthly bidweek price at the tailgate of the Yscloskey Plant as the value under this paragraph even though your gas did not flow to that index pricing point during that production month.

The third scenario is when there are multiple sequential pricing points on a pipeline through which you could transport your gas. In this scenario, you must base your value for royalty purposes on the first index pricing point after your gas enters that pipeline.

Under paragraph (c), the lessee can only use an index pricing point if it could physically transport its gas to that index pricing point because there is a pipeline or series of pipelines that physically connect to the lease and flow from the lease to the index pricing point. We will exclude the use of index pricing points where a lessee cannot sell its gas.

If the lessee can transport its gas to only one index pricing point, the lessee must base its value under paragraph (c)(1)(i) on the highest reported monthly bidweek price for that index pricing point in the ONRR-approved publication for the production month. If the lessee can transport its gas to more than one index pricing point, the lessee must base its value under paragraph (c)(1)(ii) on the highest reported monthly bidweek price for the index pricing points to which the lessee could transport its gas in the ONRR-approved publication for the production month. However, under paragraph (c)(1)(iii), if there are sequential index pricing points on a pipeline, the lessee must base its value on the first index pricing point at or after the lessee's gas enters the pipeline.

We recognize that index pricing points are normally located off of the lease and, frequently, are at lengthy distances from the lease. Thus, under paragraph (c)(1)(iv), we allow a lessee to reduce the highest reported monthly bidweek price by a set amount to account for transportation costs that a lessee would incur to move the gas from

the lease to an applicable index pricing point. We will allow a lessee to reduce the highest reported monthly bidweek prices by 5 percent for sales from the OCS Gulf of Mexico and by 10 percent for sales from all other areas, but not by less than 10 cents per MMBtu or more than 30 cents per MMBtu.

Paragraph (c)(1)(v) states that, after you select an ONRR-approved publication available at

www.onrr.gov,

you may not select a different publication more often than once every two years. We will also, under paragraph (c)(1)(vi), exclude individual index prices from this option if we determine that the index price does not accurately reflect the value of production. We will post a list of excluded index pricing points at

www.onrr.gov.

Paragraph (c)(2) explains that you may not take any other deductions from the value calculated under this paragraph (c) because you would already receive a reduction for transportation under paragraph (c)(1)(iv).

Public Comment:

Public interest groups supported the changes as an overall effort to provide greater clarity and transparency to the valuation process. A State commenter and STRAC opposed using an index-based option for reasons identified below.

While industry commenters supported the idea of an index-based method, they did not support the method as proposed. Industry commenters explained that the proposed index-based method results in a value so far above what is reasonable that few lessees would choose to use it. Commenters argued that using the highest bidweek price results in an inflated value for royalty purposes and is neither reasonable nor justified.

ONRR Response:

The value under an index-based valuation option is reasonable and justified because of the benefits that it affords to the lessee. Lessees have the burden of showing that none of the costs that they incur and deduct are costs to place their gas production in marketable condition.

Burlington Res. Oil & Gas Co. LP

U.S. Dep't of the Interior,

No. 13-CV-0678-CVE-TLW, 2014 WL 3721210, at *12 (N.D. Okla. July 24, 2014). This burden includes separating or “unbundling” costs associated with putting production in marketable condition as discussed in

Burlington.

If the lessee chooses to use the index-based option, it will relieve the lessee of those responsibilities. While this method benefits lessees, it must also protect the interests of the Federal lessor. The index-based valuation method does just that.

Public Comment:

Industry commenters argued that the requirement to use the highest index price at a pricing point to which a lessee's gas

could

flow effectively requires a lessee to pay royalty on the highest theoretically obtainable price, even though that price is not, in fact, obtainable. They explained that ONRR cites no authority or justification for this proposed standard. Instead, the commenters suggested that the rule require a lessee to base the value of its gas on the index where the lessee's gas actually flowed.

ONRR Response:

This provision protects the interests of the Federal lessor, while also simplifying the royalty reporting process for industry. If this rule required a lessee to calculate royalty on the basis of the index pricing point(s) to which the gas did flow, we would require companies to trace production, potentially through a series of affiliated transactions, and determine what volumes of gas flowed to which index pricing points. This increases the burden for both industry and us. We retained this provision in the final rule because it is consistent with the administrative simplicity that the index-based method seeks to achieve.

Public Comment:

Industry commenters stated that the fixed adjustments for transportation are too low and do not reflect current gas transportation rates.

ONRR Response:

We analyzed transportation rate data, as we discussed in the Procedural Matters section, and determined that the rates, as proposed, are a reasonable reduction to the index price.

Public Comment:

A State commenter expressed concern over the potential manipulation of prices, providing that commercial price bulletins are subject to manipulation and, indeed, have been manipulated.

ONRR Response:

We recognize the State's concern, but the index-based valuation method protects the Federal and State royalty interests for the following reasons: (1) Federal Energy Regulatory Commission (FERC) must approve pricing publications, and the publication companies also have protections to prevent and discourage price manipulation; (2) we have the discretion to disallow the use of price points that are not liquid and are more subject to manipulation; (3) we designed the index-based valuation method to generally result in a value higher than gross proceeds because of the simplicity and clarity that it affords to lessees; and (4) index prices are a trusted measure of value in the gas sales industry and the basis for many arm's-length sales contracts.

Public Comment:

STRAC requested that (1) States have the option to “opt in” for index-based valuation (similar to Indian Tribes for Indian gas valuation); (2) there be some “price testing” on the use of these index prices; and (3) there be a “true-up” to ensure that the index-based valuation was higher than a company's gross proceeds.

ONRR Response:

The index-based value protects both Federal and State interests. We analyzed Form ONRR-2014 royalty data and compared it to index prices for the years 2007 through 2010. We found that the index price was consistently higher than the average value received under gross proceeds. A rule that allows each State to choose to opt in or requires an annual true-up negates the administrative simplicity and clarity that we intend for the index-based option.

Public Comment:

One industry trade group commented that ONRR's proposal would burden small operators with the added expense required to subscribe to an industry price publication, which they believe is an unnecessary cost.

ONRR Response:

We note that there is, potentially, an additional expense if a company values their gas under the index-based option. We consider this potential additional expense to be a cost of doing business associated with properly reporting and paying Federal royalties.

Public Comment:

Industry commenters strongly urged that the index-based option be available to value arms-length transactions. These commenters noted that the 1995-1996 Federal Gas Valuation Negotiated Rulemaking Committee recommended the same. One industry trade group specifically stated, “ONRR should afford Federal gas lessees the option of using an index-pricing option to value royalties under arm's-length sales to avoid the burden of chasing gross proceeds to distant markets and to obviate the unnecessary step of creating an affiliate simply for the purpose of affording the lessee the regulatory option of choosing index pricing.”

ONRR Response:

Gross proceeds under valid arm's-length transactions are the best measure of value. The use of index prices as one option for valuing non-arm's-length transactions is appropriate because of the complex nature of transactions between affiliates and the potential administrative burden of pursuing and supporting the value under the first arm's-length sale. In this final rule, we will not expand the index-based option to arm's-length sales.

No-sale situations:

Paragraph (d)(1) provides that, if you have no written contract or no sale of gas subject to this section, and there is an index pricing point for the gas, then you must value your gas under the index-pricing provisions of paragraph (c) of this section unless ONRR values your gas under § 1206.144. We intended this provision to address situations including, but not limited to, when (1) the lessee sells its gas to an affiliate, and the affiliate uses the gas in its facility; (2) the lessee sells its gas to an affiliate, the affiliate resells the gas to another affiliate of either the lessee or itself, and that affiliate uses the gas in its facility; (3) the lessee uses the gas as fuel for its other leases in the field or area; or (4) the lessee delivers gas to another person as payment for an overriding royalty interest that the other person holds.

Public Comment:

A commenter noted that lessees do not sell gas used or lost along the pipeline and may currently value those volumes under the benchmark valuation regulations. The commenter stated that, previously, using the price that the lessee received for the gas that it sold as the basis to value its gas used or lost along the pipeline was a much more certain method of valuing gas, which also satisfied benchmark two. Instead, the commenter argues that the rule requires the lessee to submit a proposed valuation method and be subject to having to make retroactive changes if ONRR does not accept the proposed method. The commenter argued that it was unfair to require lessees who cannot otherwise use the index-based option (those making arm's-length sales) to have to use the index-based pricing to value gas used or lost along a pipeline and adds unnecessary complexity.

ONRR Response:

We thank this commenter for the insightful comment. We acknowledge that the proposed rule was not clear in providing a method for a lessee to use to value its gas used or lost along a pipeline prior to sale and disallowed fuel used in a gas plant. To add clarity and simplicity, we renumbered the proposed paragraph (d) to paragraph (e). For the new paragraph (d), we inserted new language that allow the lessee to value this gas for royalty purposes using the same royalty valuation method for valuing the rest of the gas that the lessee sells.

In addition to the four situations above, and in the preamble to the proposed rule, we note that the lessee should use new paragraph (e) when the lessee is required to pay royalty on vented, flared, or otherwise lost gas as the BLM or Bureau of Safety and Environmental Enforcement (BSEE) determined.

Public Comment:

A company stated that the proposed regulation does not provide a method to value its gas when the lessee did not sell its gas but, rather, used it on site to generate electricity. It also argued that eliminating the fourth benchmark (netback) in the previous rule could negatively affect lessees that use gas to generate electricity because an index price is not an accurate indicator of market value.

ONRR Response:

We disagree with the comment because this final rule addresses the situation wherein a lessee does not sell its gas because the gas is used on site to generate electricity under § 1206.141(e). This paragraph provides that, where there is no sale of the gas and there is not an active index pricing point, we will value your gas under § 1206.144(f).

2. Calculating Royalty Value for Processed Gas Sold Under an Arm's-Length or Non-Arm's-Length Contract (§ 1206.142)

Percentage-of-Proceeds (POP) contracts:

Paragraph (a)(2) applies to situations where a lessee sells its gas before processing and must base their royalty payment on any constituent products, resulting from processing, such as residue gas, NGLs, sulfur, or carbon dioxide. This final rule requires lessees to value POP contracts, percentage-of-index contracts, and contracts with any variations of payment based on volumes or the value of those products as processed gas.

Public Comment:

Commenters from industry, industry trade groups, and STRAC opposed this change. Industry commenters and STRAC focused their comments on the reporting burden and financial impact of this change. One commenter explained, “Because POP contracts have, since, November of 1991 been subject to the unprocessed gas valuation regulations, many companies do not have accounting systems set up to report anything other than a single product code 04 line.” The commenters explain that this proposed change would impose significant accounting system costs and delays in reporting.

One company stated that the current regulations recognize that the lessee no longer has title to or control over production after its POP buyer takes possession at the wellhead or plant inlet, highlighting that the lessee is not obligated to place residue gas and plant products in marketable condition. It believes that, by treating arm's-length POP contracts as sales of processed gas, ONRR improperly places the burden on the lessees to bear the costs to place residue gas and plant products in marketable condition despite the fact that the lessees do not have title to or control over same.

ONRR Response:

We understand that this change may increase the number of reported lines and may require some companies to adjust their systems. Yet, if a company is in compliance under the previous rules (not taking more than the allowance limits without approval, adding back costs associated with placing the gas into marketable condition, adding back marketing fees, etc.), this change should not be overly burdensome. This change increases data transparency, more accurately values the products sold under these types of sales contracts, and allows us to better monitor allowances and account for royalty interest more quickly and accurately.

Contrary to the commenter's assertions, past regulations did place the responsibility on lessees who sell their gas at the wellhead under POP-type contracts to place the residue gas and gas plant products into marketable condition at no cost to the Federal government. Simply selling the gas at the wellhead does not mean that the gas is in marketable condition—one must look to the requirements of the main sales pipeline. The U.S. District Court for the Northern District of Oklahoma supported ONRR's position under the past regulations, finding that, “Whether gas is marketable depends on the requirements of the dominant end-users, and not those of intermediate processors”

Burlington Res. Oil & Gas Co. LP

U.S. Dep't of the Interior,

No. 13-CV-0678-CVE-TLW, 2014 WL 3721210, at *11 (N.D. Okla. July 24, 2014).

Valuation of keepwhole contracts:

Paragraph (a)(3) states that the lessee must value gas processed under a “keepwhole” contract as processed gas. Under § 1206.20, we define the term “

keepwhole contract

” as a processing agreement under which the processor compensates the lessee by delivering to the lessee a quantity of residue gas (after processing) that is equivalent to the quantity of gas the processor received (prior to processing), normally based on heat content, less gas used as plant fuel and gas that is unaccounted for and/or lost. The lessee does not receive NGLs under these contracts. We often find that lessees are confused about how to value, for royalty purposes, gas processed under such contracts and then sold. This provision clarifies that a lessee must value gas processed under a keepwhole contract as processed gas. That is, royalty is based on 100 percent of the value of residue gas, 100 percent

of the value of gas plant products, plus the value of any condensate recovered downstream of the point of royalty settlement prior to processing, less applicable transportation and processing allowances.

Public Comment:

Commenters from industry trade groups and STRAC opposed this provision. They believe that ONRR should eliminate the requirement to report gas processed under a keepwhole contract as processed gas. The industry trade groups explained that companies do not have the data to report keepwhole contracts as processed gas. STRAC added that valuing keepwhole contracts as processed gas does not, in their experience, result in additional revenue collections, but it requires a significant amount of work for both auditors and industry.

ONRR Response:

Our regulations require lessees to base their royalties for gas sold after processing on the values of condensate, residue gas, and gas plant products resulting from processing gas produced from a Federal lease. Lessees sell gas processed under keepwhole contracts after processing, and, therefore, lessees should value their gas as such. This requirement also protects the public from hidden processing deductions that the lessee takes that may exceed the 66

2/3

percent limit of the value of the NGLs. Additionally, numerous entities rely on and scrutinize our data, making accurate reporting essential.

To aid lessees in their effort to properly compute royalties for gas processed under a keepwhole contract, we published a reporter letter dated November 21, 2012 (Reporter Letter). The Reporter Letter provided guidance on how to report keepwhole contracts, including instructions for situations where the lessee receives no NGL volume or value data. It is important to note that, in most cases, this requirement does not increase the royalties that a lessee pays because the lessee may include the difference in value between the gallons of NGLs that the plant recovered and the MMBtu-equivalent of the NGLs returned to the producer in its processing allowance.

First arm's-length sale:

In this final rule, ONRR eliminated the non-arm's-length valuation benchmarks. Instead, this final rule requires lessees to value residue gas and gas plant products based on how they sell their residue gas and gas plant products (such as using (1) the first arm's-length-sale prices, (2) optional index prices, or (3) volume weighted average of the values established under this paragraph for each contract for the sale of gas produced from that lease). Under § 1206.142(c)(2), if you sell or transfer your Federal residue gas and gas plant products to your affiliate, or some other person at less than arm's-length, and that person or its affiliate then sells the residue gas and gas plant products at arm's-length, royalty value will be the other person's (or its affiliate's) gross proceeds under the first arm's-length contract. However, two exceptions apply: (1) Lessees may elect to use the index-pricing option under § 1206.142(d) of this section, or (2) ONRR decides to value your residue gas and gas plant products under the default valuation provision in § 1206.144.

Public Comment:

ONRR received comments from a State and a public interest group supporting ONRR's proposal for lessees to value non-arm's-length dispositions of residue gas and gas plant products based on the first arm's-length sale rather than the benchmarks contained in the previous rule. Several industry commenters asserted that tracing their affiliates' arm's-length gross proceeds is complicated and burdensome. One industry trade group remarked that § 1206.142(c) does not address costs unique to marketing and transporting CNG and LNG, where the first arm's-length sale may be at a distant, international market.

ONRR Response:

The values established in arm's-length transactions are the best indication of market value. We recognize that changes in industry and the marketplace may make it difficult for a lessee to value its gas using the benchmarks. To address these difficulties, we eliminated the benchmarks to provide early certainty and gave lessees with non-arm's-length sales the option to value gas based on the first arm's-length sale or index prices.

Index-based valuation option:

Paragraph (d)(1) applies to residue gas. It has the same index-price option as § 1206.141(c)(i) through (vi). We discuss using index pricing points in § 1206.141 of this Preamble.

Paragraph (d)(2) contains the index-based pricing option for NGLs. Under paragraph (d)(2)(i), if you sell NGLs in an area with one or more ONRR-approved commercial price bulletins available at

www.onrr.gov,

you may choose one bulletin, and your value for royalty purposes would be based on the monthly average price for that bulletin for the production month. We consider you to be selling NGLs in an area with an ONRR-approved commercial price bulletin if actual sales of NGLs that the plant processing your gas recovers are made using NGL prices in an ONRR-approved commercial price bulletin. For example, in our experience, actual sales of NGLs recovered in plants in New Mexico commonly reference Mont Belvieu, Texas, prices in Platts, while actual sales of NGLs recovered in plants in certain parts of Wyoming reference Mont Belvieu, Texas, or Conway, Kansas, prices. If you process your gas at one of these plants with these types of actual sales arrangements, we will consider you to be selling NGLs in an area with an ONRR-approved commercial price bulletin. In that case, you may elect to value your NGLs using the index-price method if your NGLs meet the requirements for using that method. We will monitor actual sales of NGLs and eliminate any area where an active market using NGLs prices in an ONRR-approved commercial price bulletin ceases to exist.

Under paragraph (d)(2)(ii), you may reduce the index-based value that you calculate under paragraph (d)(2)(i) by a specified amount to account for a theoretical processing allowance and Transportation and Fractionation (T&F). Therefore, the reduction includes two components that we calculated: (1) An allowance based on processing allowance information lessees report to us and (2) T&F based on our review of gas plant contracts and gas plant statements.

For the processing allowance component, ONRR examined processing allowances that lessees and others reported from January 2007 through October 2011. We segregated the data into two subsets: (1) The Gulf of Mexico (GOM) and (2) onshore Federal leases and OCS leases other than those in the GOM. We segregated the leases geographically because the GOM is closer to major market centers at Mont Belvieu, Napoleonville, and Geismer/Sorrento and, generally, has its own processing, transportation, and fractionation regimen that is distinct from the rest of the country. It is not fair or accurate to benchmark processing for the entire country based on the economics of GOM processing.

We could not segregate non-arm's-length processing allowances because lessees do not identify processing allowances as arm's-length or non-arm's-length when they report to ONRR. Rather, we calculated a weighted-average cents-per-gallon processing allowance by month for both GOM and all other Federal leases. Using the weighted average cents-per-gallon processing allowance that we calculated, we determined the average allowance rate over the five-year period, along with the maximum and minimum monthly rates as follows:

GOM

(¢/gal)

Other

(¢/gal)

Average Rate

Maximum Rate

Minimum Rate

Because we intend for this option to provide a simple method for us to calculate and provide to lessees, we used the minimum, rather than the average rate, for the processing allowance portion of the deduction. For both the GOM and all other Federal leases, the minimum rate is seven cents less than the average rate. We find that (1) the minimum allowance best protects the public interest and (2) a lessee experiencing higher allowable costs than this rate does not have to elect to use this option and the lower cost allowance. Moreover, seven cents is a reasonable tradeoff given the simplicity, certainty, and commensurate administrative savings that this option would provide to a lessee.

For the T&F part of the reduction, we examined contracts that specified T&F. If contracts did not specify T&F, we looked at the gas plant statements. If the statements listed T&F as a line item, we used that line item as the T&F. If the statements did not list T&F as a line item, we calculated the difference between the price on the plant statement and an appropriate published price to approximate the T&F. We then averaged these T&F costs for GOM, New Mexico, and other, as follows:

GOM

New Mexico

Other

Average T&F

5¢/gal

7¢/gal

12¢/gal.

We broke out New Mexico because the T&F fees for New Mexico plants were consistently around seven cents per gallon and were considerably less than for other onshore plants. We then added the processing allowances that we calculated and the T&F. Based on the five years of data discussed above, we calculated that the total NGLs reductions that lessees could use under this option are as follows:

GOM

New Mexico

Other

NGLs Deduction

15¢/gal

22¢/gal

27¢/gal.

Under paragraph (d)(2)(ii), rather than publish the reductions in the CFR, we will post the reductions at

www.onrr.gov

for the geographic location of your lease. ONRR will calculate the reductions using the method explained above. This process will give us the flexibility to quickly recalculate and provide revised reductions to lessees in response to market changes. This method is binding on you and us. Under paragraph (d)(4), we will update the allowable reductions periodically using this method and post changes at

www.onrr.gov

Paragraph (d)(2)(iii) explains that, after you select an ONRR-approved commercial price bulletin available at

www.onrr.gov,

you may not select a different commercial price bulletin more often than once every two years. Under paragraph (d)(3), you may not take any other deductions from the value that you used under this paragraph (d) because it already includes reductions for transportation and processing.

Paragraph (e) mirrors § 1206.141(d); this explains how you must value certain volumes of processed gas or NGLs that are used as fuel, lost, or retained as a fee under the terms of a sales or service agreement.

Paragraph (f) mirrors § 1206.141(e); this explains how you must value your processed gas and NGLs if you have no written contract for the sale of gas or no sale of the gas subject to this section.

Public Comment:

Several industry commenters noted that ONRR provided no adjustment to the index price for transportation of the NGL component of the gas stream from the wellhead to the gas plant. The only adjustment is for the costs of transporting and fractionating the recovered NGLs. One commenter suggested that ONRR use the same adjustment that ONRR used in calculating the index-based value for the unprocessed or residue gas (10 percent, but not less than 10 cents per MMBtu or more than 30 cents per MMBtu).

ONRR Response:

We do not agree that an adjustment is necessary. The adjustment would be small, and not including it is fair considering our use of the average index price instead of the high index price. This final rule does not require a lessee to use the index option, but the lessee can elect to base its royalty value on the first arm's-length sale.

Public Comment:

One industry trade group requested that ONRR clarify whether we intend to use the “average highest price” or the “average average price” for the index-based valuation method for NGLs.

ONRR Response:

In our experience, NGL price publishers publish an average and high NGL price. They do not publish an “average average” or “average high” price. We will use the average index price.

Public Comment:

One industry trade group commented that New Mexico producers were particularly disadvantaged by the T&F rates that ONRR proposed.

ONRR Response:

Our experience indicates that seven cents per gallon is a reasonable estimate for T&F rates in New Mexico. T&F rates are generally lower in New Mexico than in the rest of the country because New Mexico producers have more direct access to Mont Belvieu, Texas.

Public Comment:

An industry commenter questioned what remedy a lessee would have if ONRR did not follow the method set forth in the preamble. The commenter noted that the proposed regulation provided that an election to use index-based pricing cannot be changed more often than once every two years. Then the commenter suggested that it is hard for a company to make an election when the basis for making the election, including ONRR's posting of the amounts that can be deducted, can be changed during the two-year period for which the election was made.

ONRR Response:

The two-year election period offers sufficient protection for lessees if we change the rates. Any changes to rates will be based on changes to the markets, which should generally correspond to changes that producers would see if they were reporting gross proceeds.

No-sale situations:

Paragraph (e)(1) provides that, if you have no written contract or no sale of gas subject to this section and there is an index pricing point for the gas, then you must value your gas under the index-pricing provisions of paragraph (d) of this section unless ONRR values your gas under § 1206.144. We intended this

provision to address situations including, but not limited to, when (1) the lessee sells its gas to an affiliate, and the affiliate uses the gas in its facility; (2) the lessee sells its gas to an affiliate, the affiliate resells the gas to another affiliate of either the lessee or itself, and that affiliate uses the gas in its facility; (3) the lessee uses the gas as fuel for its other leases in the field or area; or (4) the lessee delivers gas to another person as payment for an overriding royalty interest that the other person holds.

Public Comment:

A commenter noted that lessees do not sell gas or gas plant products used or lost along the pipeline and may currently value those volumes under the benchmark valuation regulations The commenter stated that, previously, using the price that the lessee received for the gas that it sold as the basis to value its gas used or lost along the pipeline was a much more certain method of valuing gas, which also satisfied benchmark two. Instead, the commenter argues that the rule requires the lessee to submit a proposed valuation method and be subject to having to make retroactive changes if ONRR does not accept the proposed method. The commenter argued that it was unfair to require lessees who cannot otherwise use the index-based option (those making arm's-length sales) to have to use the index-based pricing to value gas or gas plant products used or lost along a pipeline and adds unnecessary complexity.

ONRR Response:

We thank this commenter for the insightful comment. We acknowledge that the proposed rule was not clear in providing a method for which a lessee shall value gas used or lost along a pipeline prior to sale and disallowed fuel used in a gas plant. In an effort to add clarity and simplicity, we will, therefore, renumber the proposed paragraph (e) to paragraph (f). For the new paragraph (e), we inserted new language that allows the lessee to value this gas for royalty purposes using the same royalty valuation method for valuing the rest of the gas that the lessee sells.

3. Determination of Correct Royalty Payments (§ 1206.143)

Default:

ONRR added a default valuation provision that allows us to value your gas, residue gas, or gas plant products under § 1206.144 or any other provision in this subpart D. We addressed comments pertaining to the “default provision” paragraph, which we detail in § 1206.101, of this Preamble.

Public Comment:

All of the commenters who addressed the default provision under Federal oil had the same comments for Federal gas, and we will not repeat them here. Please refer to the public comments for Federal oil for an overall discussion of the default provision.

Specifically for gas, several commenters stated that ONRR lists comparability factors in its valuation method that contradict what ONRR permits lessees to consider. They state, for example, that ONRR may look to the value of like-quality gas, residue gas, or gas plant products in the same or nearby fields or plants, but it is not permitting lessees the option to use these standards as part of their valuation processes in the first instance.

ONRR Response:

We will only respond, here, to those comments that are specific to gas, residue gas, and gas plant products. For a broader response to the default provision, because it also relates to Federal gas, please see ONRR's response to Federal oil, which we detail in § 1206.101, of this Preamble.

We disagree with commenters that state that we list comparability factors in our default valuation method that contradict what we permit the lessees to consider. Valuation, first and foremost, is generally based on the gross proceeds accruing to the lessee under an arm's-length contract or received under the first arm's-length sale following a sale to an affiliate. Only in rare situations, when normal valuation methods are not viable or there has been other extenuating circumstances, will we defer to the valuation criteria listed in § 1206.144.

This final rule delineates factors that we may consider if we decide to determine the value of natural gas for royalty purposes under the default provision. Those factors may include, but are not limited to the following: the value of like-quality gas in the same field or nearby fields or areas; the value of like-quality residue gas or gas plant products from the same plant or area; public sources of price or market information that we deem to be reliable; information available or reported to us, including but not limited to, on Form ONRR-2014 and Form ONRR-4054; costs of transportation or processing, if we determine that they are applicable; and any information that we deem relevant regarding the particular lease operation or the salability of the gas.

Misconduct:

ONRR added a new definition for the term misconduct. We addressed comments pertaining to this definition, which we detail in § 1206.20, of this Preamble.

4. Determination of gas value for royalty purposes (§ 1206.144)

Default:

ONRR added a default valuation provision which allows us to value your gas under § 1206.144 or any other provision in this subpart. We addressed comments pertaining to the “default provision” paragraph, which we detail in § 1206.101, in this Preamble.

Area:

ONRR removed the phrase “legal characteristics” from the definition of area. We addressed comments pertaining to this definition and the regulations that it affects, detailed in § 1206.105, in this Preamble.

5. Responsibility To Market Production and To Place Production into Marketable Condition (§ 1206.146)

Public Comment:

Although ONRR did not modify the wording in this section, several commenters argue that our proposal eliminates separately defined requirements for processed and unprocessed gas and replaces them with a consolidated marketable condition requirement. This, commenters argue, may result in the lessee being required to place processed gas in marketable condition twice—once as gas and again as residue gas.

ONRR Response:

The regulations have always required the lessee to put its production into marketable condition at no cost to the Federal government. This requirement remains unchanged, as does a lessee's duty to put its production into marketable condition.

6. Valuation determination requests (§ 1206.148)

Guidance and Determinations:

ONRR clarified how a lessee may request a valuation determination from us. We addressed comments pertaining to guidance and determinations in § 1206.108. For the reasons discussed in response to comments, we deleted the words “or guidance” from the title and paragraph (a) of this section.

7. Accounting for Comparison (§ 1206.151)

ONRR proposed to move the current provisions under § 1206.155 to proposed § 1206.151 and requested comments regarding whether or not to retain the requirement to perform accounting for comparison (dual accounting) for gas produced from Federal leases.

Public Comment:

Industry and State commenters supported removing the Federal dual accounting provision from the regulations. Commenters stated that, because residue gas is now valued based on the first arm's-length sale or index-based option, the criteria that triggered

dual accounting, a non-arm's-length sale of residue gas after processing, is no longer valid.

STRAC agreed that, under current market conditions, accounting for comparison was no longer necessary, but they questioned how ONRR would respond to potential changes in the gas market in the future.

ONRR Response:

We removed the requirement to perform accounting for comparison for gas produced from Federal leases from the final rule. We agree that the gas valuation method under § 1206.142 renders accounting for comparison for Federal gas production unnecessary. Should significant changes in the gas market occur in the future, we will revisit the need for Federal dual accounting in a future rulemaking. Further, § 1206.140(c) recognizes the primacy of lease terms over regulations and, should the terms of a lease require dual accounting, lessees are clearly subject to the dual accounting requirement.

8. General Transportation Allowance Requirements (§ 1206.152)

Subsea gathering:

ONRR added a new provision stating that you may not take a transportation allowance for the movement of gas produced on the OCS from the wellhead to the first platform. This addition, along with the changes to the definition of gathering, rescinds the Deep Water Policy. We addressed comments pertaining to this issue, which we detail in § 1206.110, in this Preamble.

Fifty-percent allowance cap and retroactive change:

ONRR eliminated the regulation allowing us to approve transportation allowances in excess of 50 percent of the value of a lessee's gas production. Any prior approvals will terminate on the date when the rule becomes final. We addressed comments pertaining to these issues, which we detail in § 1206.110, in this Preamble.

Eliminating transportation factors:

Previously, ONRR allowed lessees to net transportation from their gross proceeds when the lessees' arm's-length contract reduced the price of the gas by a transportation factor. We eliminated this provision and, instead, require lessees to report such costs as a separate entry on Form ONRR-2014. We addressed comments pertaining to this issue, which we detail in § 1206.110, in this Preamble.

Misconduct:

ONRR added a new definition for the term “misconduct.” We addressed comments pertaining to this issue, which we detail in § 1206.20, in this Preamble.

Default:

We addressed comments pertaining to the “default provision” paragraph, which we detail in § 1206.101, in this Preamble.

Unreasonably high transportation costs:

We addressed comments pertaining to this issue, which we detail in § 1206.104, in this Preamble.

9. Determination of Transportation Allowances for Arm's-Length Transportation Allowances (§ 1206.153)

Pipeline losses:

We addressed comments pertaining to this issue, which we detail in § 1206.111, in this Preamble.

In the proposed rule, we removed the provision in the previous regulations under § 1206.157(b)(5). We neglected to remove regulatory language in proposed § 1206.153(b)(7). Therefore, in this final rule, we deleted, “or ONRR approves your use of a FERC or State regulatory-approved tariff as an exception from the requirement to calculate actual costs under § 1206.154(l) of this subpart.”

Written contracts:

We added a new provision stating that we will determine transportation allowances if lessees do not have a written contract for the arm's-length transportation of gas. We addressed comments pertaining to this issue, which we detail in § 1206.104, in this Preamble.

Eliminating transportation factors:

Previously, we allowed lessees to net transportation from their gross proceeds when the lessees' arm's-length contract reduced the price of the gas by a transportation factor. We eliminated this provision and alternatively require lessees to report such costs as a separate entry on Form ONRR-2014. We addressed comments pertaining to this issue, which we detail in § 1206.110, in this Preamble.

Boosting:

Under paragraph (c)(8), we specify that the costs of boosting residue gas are not allowable costs of transportation.

Public Comment:

An industry commenter argued that this new provision effectively requires the unbundling of arm's-length transportation agreements. Industry also argues that the additional disallowance of boosting residue gas in this section and in § 1202.151(b) is either redundant or results in the lessee having to pay for some marketable condition costs twice for processed gas. Industry states that boosting residue gas is part of plant costs, and it is not associated with a transportation system or transportation allowance.

An industry commenter suggested that eliminating the proposed boosting language in paragraph (c)(8) will ensure consistency in product valuation for all natural gas, whether processed, unprocessed, conventional, or coal bed methane and all plants (cryogenic, lean oil absorption, refrigeration, and CO

removal). According to the commenter, elimination of the boosting language will also ensure proper treatment involving leases that produce at a pressure above the marketable condition requirement or for offshore leases where the gas leaves the production platform at or above the marketable condition pressure by requiring the gas be placed into marketable condition only once.

ONRR Response:

Current regulations and case law make clear that the cost incurred—including any fuel used—to boost gas (such as compress residue gas after processing) is not a deductible cost of processing or transportation (30 CFR 1202.151(b);

see also Devon Energy Corporation

Kempthorne,

551 F.3d 1030 (D.C. Cir. 2008), cert. denied, 130 S. Ct. 86 (2009), (finding that boosting is not deductible even if gas is in marketable condition before entering a gas processing plant)). Yet a number of members of industry continue to deduct costs incurred to boost residue gas as either a processing or a transportation allowance, and they argue that it is proper to do so. The inclusion of paragraph (c)(8) reinforces current regulations and case law and therefore we retained it in the final rule.

10. Determination of Transportation Allowances for Non-Arm's-Length Transportation Contracts (§ 1206.154)

Pipeline losses:

Under paragraph (c)(2)(ii), we eliminated the provision that allows lessees to deduct the costs of pipeline losses, both actual and theoretical, under non-arm's-length transportation situations. We addressed comments pertaining to this issue, which we detail in § 1206.111, in this Preamble.

BBB bond rate:

We reduced the multiplier on any remaining undepreciated capital costs from 1.3 to 1.0 times the Standard & Poor's BBB bond rate. We addressed comments pertaining to this issue, which we detail in § 1206.112, in this Preamble.

FERC or state-regulatory-agency approved tariffs:

We removed the provisions allowing a lessee with a non-arm's-length contract to apply for an exception to use FERC or State-regulatory-agency approved tariffs as an exception from the requirements to calculate actual costs.

Public Comment:

Several companies and industry trade groups opposed removing the provision, stating that it lacked justification. One commenter stated, “Many of these situations involve affiliated pipelines where obtaining the information to do these calculations would be problematic and

burdensome due to the governmental restrictions placed on pipeline companies in sharing information with shippers.”

ONRR Response:

Lessees may deduct their reasonable actual costs of transportation under this section. The burden lies with the lessee to calculate these reasonable actual costs of transportation. We removed this rarely-used provision to apply for an exception to create consistency with the Federal oil valuation regulations and promote a more consistent application of the actual cost allowance method.

11. Reporting Requirements for Arm's-Length Transportation Contracts (§ 1206.155)

Eliminating transportation factors:

Eliminating transportation factors will require lessees to report any transportation costs embedded in an arm's-length contract as a separate line entry on Form ONRR-2014. We addressed comments pertaining to this issue, which we detail in § 1206.115, in this Preamble.

12. Reporting Requirements for Arm's-Length Transportation Contracts (§ 1206.156)

In the proposed rule, we removed the provision in the previous regulations under § 1206.157(b)(5). We neglected to remove regulatory language in proposed § 1206.156(d). Therefore, in this final rule, we deleted this paragraph.

13. Processing Allowances (§ 1206.159)

We eliminated the regulation allowing us to approve processing allowances in excess of 66

2/3

percent of the value of a lessee's gas production. Any prior approvals will terminate on the date when the rule becomes final. We addressed issues related to prior approval terminations, which we detail in § 1206.110, in this Preamble.

Public Comment:

We received comments from States and public interest groups generally supporting eliminating ONRR approval to exceed the 66

2/3

-percent allowance cap on processing allowances. However, a State commenter asserted that the 66

2/3

-percent cap, itself, was too broad. A State suggested that ONRR calculate allowance caps for each State and use a percentage based on the average processing costs in each State over a ten-year period. A State commenter suggested that ONRR update and post such percentages on its Web page.

ONRR received comments from companies and industry trade groups opposing the proposed rule's elimination of ONRR approval to exceed a 66

2/3

-percent limitation on processing allowances. These commenters generally stated that the right to request approval to exceed the 66

2/3

-percent limitation needs to be reinstated because its removal denies a lessee the ability to deduct all of its actual, reasonable, and necessary processing costs when those costs exceed 66

2/3

percent. The commenters believe that this is especially true when the physical make-up of the gas warrants complex plant designs that result in higher costs. Last, commenters take issue with ONRR terminating any approval that it previously issued for a lessee to exceed the 66

2/3

-percent limitation.

ONRR Response:

The comments regarding the 66

2/3

-percent processing allowance mirror the comments that we received for the 50-percent limitation on transportation allowances for oil. Please refer to our comments regarding the “Fifty-percent allowance cap,” which we detail in § 1206.110, in this Preamble.

Extraordinary processing allowances and retroactive changes:

We eliminated the provision that allows a lessee to request an extraordinary processing cost allowance. We previously allowed lessees to deduct processing costs up to 99 percent of the value of the gas plant products extracted

and

up to 50 percent of the value of the residue gas. This final rule also terminates the two existing extraordinary processing cost allowance approvals. We addressed issues related to the prior approval terminations, which we detail in § 1206.110, in this Preamble.

Public Comment:

Industry commenters and a State commented that ONRR should retain the extraordinary processing cost allowance provision and argued that ONRR failed to provide specific evidence that circumstances or improvements in technology have changed enough to warrant the termination of the two existing approvals.

ONRR Response:

The Department added the extraordinary processing cost allowance provision to the 1988 regulations to account for the costs of processing unique gas streams based on the technology available at that time. The Department has not approved an extraordinary processing cost allowance since 1996, and we maintain that the markets and the technology have changed sufficiently such that this provision and these approvals are no longer necessary.

Default:

In drafting this final rule, we did not include the default provision in this section. We intended to include the default provision here as evidenced by our discussion of the default provision in the economic analysis of the proposed rule. Therefore, we added the default provision in § 1206.159(e), which applies to processing allowances calculated under §§ 1206.160 and 1206.161. We addressed comments pertaining to the “Default Provision” paragraph, which we detail in § 1206.101, in this Preamble.

14. Processing Allowances Under an Arm's-Length Contract (§ 1206.160)

Unreasonably high processing costs:

We moved the requirements for non-arm's-length processing allowances to a separate § 1206.161. Because the requirements for determining processing allowances under an arm's-length contract are essentially the same as those for determining transportation allowances under an arm's-length contract, we made the same changes to processing allowances in this section as those that we made for arm's-length transportation allowances. Newly added paragraph (c) applies if you have no written contract for arm's-length processing of gas. In that case, we will determine your processing allowance under § 1206.144. We addressed comments pertaining to this general issue, which we detailed under § 1206.104, in this Preamble.

Misconduct:

We added a new definition for the term misconduct. We addressed comments pertaining to this issue, which we detailed under § 1206.20, in this Preamble.

Default:

We addressed comments pertaining to the “default provision,” which we detail under § 1206.101, in this Preamble. In conjunction with our additions in § 1206.159(e) explained above, and to make this section consistent with the transportation allowances sections, we deleted paragraph (a)(3).

D. Specific Comments on 30 CFR Part 1206—Product Valuation, Subpart F—Federal Coal

1. Calculating Royalty Value for Coal I or My Affiliate Sell(s) Under an Arm's-Length or Non-Arm's-Length Contract (§ 1206.252)

Index prices for coal lessees that do not sell under arm's-length contracts:

In contrast to the Federal oil and gas valuation regulations, the coal regulations do not allow lessees that do not sell their coal under arm's-length contracts to value their coal based on index prices.

Public Comment:

ONRR received comments from industry trade groups, public interest groups, individual commenters, and companies suggesting that ONRR provide coal lessees who do not sell coal under arm's-length

contracts the option of valuing coal based on index prices, similar to the options for oil and gas lessees. The commenters believe that using an index price would provide simplicity, predictability, and transparency to the value of coal not sold under arm's-length contracts. ONRR received a comment from a Tribe indicating that it would be willing to accept index prices as a floor value of coal if there is a reliable index. Several commenters proposed that ONRR could generate an index to value coal not sold at arm's-length.

ONRR Response:

We appreciates the comments, but declined to provide lessees who do not sell their coal under arm's-length contracts the option to use index prices to value their coal. As mentioned in the “General Comments” section, we are not aware of any published index prices for coal that cover a wide array of coal production. Currently, there are few, if any, indexes for coal, and they are not as widely used as they are for oil and gas. Also, although the existing indexes vary depending on MMBtu content, they do not take into account other variations in the quality of coal, such as ash or sulfur content.

As to the comments that we should generate an index price for lessees to use, we decline to do so at this time. First, as mentioned above, there are no reliable indexes for coal like there are for oil and gas, making it difficult for us to create index-based prices similar to those used in our Indian oil and gas regulations. Second, if we use arm's-length sales from the royalty reports that we receive, we risk divulging proprietary data. We will monitor the coal market and may be open to considering an index-based valuation option if the indexes become viable in the future.

First arm's-length sales:

Consistent with how we require lessees to value other commodities, we are requiring lessees to value non-arm's-length dispositions of Federal coal at the first arm's-length sale.

Public Comment:

ONRR received numerous comments on our proposal to remove the benchmarks and, instead, value coal at the first arm's-length sale. Many industry commenters petitioned ONRR to retain the previous rule's benchmark system to value coal sold under non-arm's-length contracts. Some commenters felt that valuing coal at the first arm's-length sale was unnecessarily complex. The commenters stated that using the first arm's-length sale as value may require the lessee to use international or electricity sales as the basis of value, which does not reflect the value of coal sold at the lease. Instead, some commenters generally expressed a view that the previous rule's benchmark system, or some modification thereof, would be a better option to determine value. Some commenters felt that the first benchmark, which requires lessees to compare their non-arm's-length sales with arm's-length sales in the same field or area, is the appropriate measure of value for coal not sold at arm's-length. In contrast, other commenters felt that the proposed rule did not go far enough. Instead, these commenters recommended that ONRR value the coal based on its final—not its first—arm's-length sale.

ONRR Response:

The values established in arm's-length transactions are the best indication of market value. There is ample evidence that arm's-length sales provide a consistent and accurate measure of all commodities for which we collect royalties. We found that the benchmarks were difficult to use in practice. There have been disputes over comparable sales, which benchmark to use, and how to properly apply those benchmarks. To address these difficulties, we simplified the rule by requiring lessees to value coal based on the first arm's-length sale.

Previously, when lessees sold coal under a non-arm's-length contract, the regulations required the lessee to use the first applicable “benchmark” to establish value. The first benchmark was the gross proceeds accruing to the lessee under its non-arm's-length sale, provided those gross proceeds were comparable to the gross proceeds that accrued to other producers not affiliated with the lessee under arm's-length sales of like-quality coal in the same area. To compare such sales, the lessee looked at prices, timing, markets, quality, and quantity of coal. The second benchmark was prices reported to a public utility commission. The third was prices reported to the Energy Information Administration (EIA) of the Department of Energy. The fourth benchmark required the lessee to use other relevant matters, including spot market prices, or other information concerning the particular lease operation or salability of the coal. The fifth benchmark was a netback method.

Although many commenters advocated for the first benchmark, industry and ONRR found it difficult to implement this provision. Acquiring arm's-length contracts to compare with the lessee's gross proceeds was challenging and, at times, impossible for lessees. Lessees cannot use their or their affiliates' comparable sales. Only in rare circumstances did the lessee have access to its competitor's information regarding the price that the competitor receives for its coal. Further, we cannot obtain or verify contracts for comparable-quality coal sold from fee or State lands. Industry and ONRR also found that it was difficult to ascertain definitively which arm's-length coal sales were comparable and which ones were not. Based on our experience, arm's-length sales are a superior indicator of value to the remaining benchmarks.

Valuing coal sold by coal cooperatives:

Section 1206.252(c) addresses sales by coal cooperatives to their members or between members. In keeping with our intent to value commodities, whenever possible, at their first arm's-length sale, we provided a definition of the term “

coal cooperatives

” in § 1206.20 and addressed sales by coal cooperatives to their members or between members in this section. Principally, coal cooperatives are formed because of some degree of mutual economic or other business interest. Consequently, transactions within coal cooperatives lack the opposing economic interests characteristic of arm's-length sales. Because coal cooperatives engage in non-arm's-length sales to and between members, we require lessees to base the value of their coal at the first arm's-length sale, wherever that may finally occur. In some cases, this may be the sale of electricity generated in a coal-fired plant.

Public Comment:

ONRR received comments supporting our distinction of coal cooperatives as engaging in other than arm's-length sales. These commenters expressed concerns that coal producers, logistics companies, and even generators of coal-fired electricity would take advantage of their affiliated status and sell coal to each other at less than market prices, thereby lowering their royalty liabilities. Conversely, numerous commenters objected to our definition of coal cooperatives. These commenters argued that our definition and the application of our rules to coal cooperatives did not accurately reflect the corporate structure of cooperatives, would penalize small producers, and deviates from our intent to value coal at the mine.

ONRR Response:

We seek a clear, consistent, and repeatable standard for valuing coal at its true market value. Coal cooperatives of varying forms (and complexity) are, primarily, designed for mutual economic advantage. We share the concerns that some commenters expressed that sales within coal cooperatives may not reflect the true market value of the coal. We require

lessees to value coal consistent with other commodities—at their first arm's-length sale between entities with competing economic interests, rather than common interests. We disagree with the comment that the definition of coal cooperatives is “unnecessary.” In fact, given the unique institutional nature of cooperatives in the coal industry—corporate relations among mine producers, logistics operations, electric generation, and overseas sales—that is not commonly found in markets for oil and gas, we deemed it imperative to define coal cooperatives for royalty purposes.

Valuing coal based on sales of electricity:

In some situations, the lessees do not sell coal but, rather, transfer the coal along a series of non-arm's-length transactions to an affiliated generator of coal-fired electricity, who then sells electricity generated from the coal. We require lessees to base the value of the coal on the value of electricity sold, less applicable deductions for transmission, generation, coal washing, and transportation.

Public Comment:

We received numerous comments, both supporting and opposing, using the value of electricity to value coal in cases of no sales or sales within coal cooperatives. Supporters argued that, in cases of no sales or non-arm's-length sales across coal cooperatives, assessing the value of coal as that of the generated electricity gives the most accurate representation of the coal's value. Some of these commenters argued that coal should be valued at the last arm's-length sale of electricity. Opponents argued that valuing coal using electric sales was a violation of the MLA, ignored and oversimplified the complexities of electric markets and contracts, and was administratively burdensome. In addition, they argued that ONRR's reference to geothermal regulations for valuing electricity was outside the scope of coal valuation.

ONRR Response:

We disagree with comments asserting that using electric sales to value Federal coal, for royalty purposes, is inconsistent with the MLA. Rather, the MLA expressly provides the Secretary's discretion to determine value: “A lease shall require payment of a royalty in such amount as the Secretary shall determine of not less than 12

1/2

per centum of the value of coal as defined by regulation.” 30 U.S.C. 207. This rule simply defines the value of coal.

As previously stated, based on our experience, arm's-length sales are the best indicator of value. Due to the complexity of affiliated interests across coal mining, logistics, and sales that many commenters referenced, the first arm's-length sale could easily be the sale of generated electricity. According to the EIA, in 2014, over 93 percent of coal consumption was used in electric generation nationally.

We require lessees to value coal based on the first arm's-length sale, regardless if that sale is for coal or electricity. However, the rule does allow lessees to deduct costs associated with converting the coal to electricity to arrive at the value of the coal at the lease—not the value of the electricity. We will only use sales of electricity to value coal in situations where the first arm's-length sale is the sale of electric power along a series of no sales or non-arm's-length sales.

2. Determination of Correct Royalty Payments (§ 1206.253)

Default:

We added a default valuation provision in § 1206.253 under which we can value a lessee's Federal coal if we decide to do so using the criteria in § 1206.254 or any other provision in these subparts.

Public Comment:

Almost unanimously, industry commenters and others who support industry's position objected to the use of ONRR's proposed default provision for coal. Several industry commenters argued against ONRR's ability to determine royalty value when coal is sold for 10 percent less than the lowest reasonable measures of market value. Commenters stated that some companies can negotiate better prices than others based on size and bargaining power.

Several industry trade associations stated that, under its default provision, ONRR could upend reasonable and settled expectations whenever we decide for any reason that it dislikes any given lessee's reported coal valuation. These industry commenters also believe (1) that this provision does not allow ONRR to honor arm's-length contracts and gross proceeds as the basis of valuation as in the past; (2) there is a lack of specific criteria for determining what is reasonable valuation; (3) the default provision should not be used for simple reporting errors; and (4) the default provision is burdensome, an overreach of valuation authority, and creates uncertainty.

Several public interest groups suggested that the default provision should be mandatory and not discretionary. They supported ONRR's proposal to establish a default valuation mechanism, which provides the agency with needed authority to ascertain the value of Federal and Indian coal where the government otherwise would fail to garner a fair return on its resource as the result of a lessee's misconduct. The commenters believe that the sources of information upon which ONRR proposes to base its determination of the coal's value are appropriate and, to the extent that they include publicly accessible information, would promote transparency. The comments from public interest groups stated that, when industry fails to abide by the terms of its commitment to market Federal coal for the mutual benefit of the lessee and the Federal government, thereby depriving the government of royalties on the full market value of its coal, the regulations should eliminate the lessee's privilege to continue to determine its own coal value and royalty payments. A comment from a public interest group stated that hesitancy of invoking this default proposition guts the method's efficacy and limits the extent to which the rule will close the first arm's-length sale loophole.

ONRR Response:

We disagree with the commenters' statements that the default provision is a radical departure from our historical valuation policy. The regulatory changes do not alter the underlying principles of the current regulations. For example, nothing in this final rule changes the Department's requirement that, for the purposes of determining royalty, the value of coal produced from Federal leases is determined at or near the lease. And nothing in this final rule modifies or alters the fact that gross proceeds from arm's-length contracts are the best indication of market value.

The default provision addresses valuation situations where circumstances result in the Secretary's inability to reasonably determine the correct value of production. Such circumstances include, but are not limited to, (1) the lessee's failure to provide documents; (2) the lessee's misconduct; (3) the lessee's breach of the duty to market; or (4) any other situation that significantly compromises the Secretary's ability to reasonably determine the correct value. The mineral statutes and lease terms give the Secretary the authority and considerable discretion to establish the reasonable value of production by using a variety of discretionary factors and any other information that the Secretary determines is relevant. The default provision simply codifies the Secretary's authority to determine the value of production for royalty purposes and specifically enumerates when, where, and how the Secretary will use that discretion.

Under this new rule, we will not second-guess arm's-length contracts to any greater or lesser degree than we

have historically. We have never tacitly accepted values received under arm's-length contracts. We analyze all types of sales contracts in our reviews to validate proper value and deductions.

The criteria that we will use to establish a royalty value under the default provision is the same basic criteria that we base all royalty values upon. Further, we specifically list these criteria in the coal regulations. Factors that we could consider if we decide that we will determine value for royalty purposes under the default provision are clearly delineated and may include, but would not be limited to, (1) the value of like-quality coal from the same mine, nearby mines, same region, or other regions, or washed in the same or nearby wash plant; (2) public sources of price or market information that we deem reliable, including but not limited to, the price of electricity; (3) information available to us and information reported to us, including but not limited to, on the Solid Minerals Production and Royalty Report (Form ONRR-4430); (4) costs of transportation or washing, if we determine that they are applicable; or (5) any other information that we deem relevant regarding the particular lease operation or the salability of the coal.

3. Determination of Coal Value for Royalty Purposes (§ 1206.254)

Default:

ONRR added a default valuation provision allowing us to value your coal under this section or any other provision in this subpart F. We address comments pertaining to the default provision, which we detail in § 1206.253, in this Preamble.

4. Valuation Determination Requests (§ 1206.258)

Guidance and Determinations:

ONRR clarified how a lessee may request a valuation determination from us. We addressed comments pertaining to guidance and determinations in § 1206.108 of this Preamble. For the reasons that we discussed in response to comments, we deleted the words “or guidance” from the title and paragraph (a) of this section.

5. General Transportation Allowance Requirements (§ 1206.260)

This section contains the requirements of the previous § 1206.261. This section also consolidates provisions applicable to both arm's-length and non-arm's-length transportation in the previous regulations and clarifies that you do not need our approval to report a transportation allowance for arm's-length or non-arm's-length transportation costs that you incur. Paragraph (c) explains in which circumstances you cannot take an allowance. Finally, we added paragraph (g), containing the default provision, which includes the requirements of previous paragraphs 1206.262(a)(2) and 1206.262(a)(3) regarding additional consideration, misconduct, and breach of the duty to market.

Fifty-percent allowance cap:

In the preamble of the proposed rule, we solicited comments on whether or not we should impose a 50-percent cap on coal transportation allowances.

Public Comment:

ONRR received several comments from public interest groups, the public, and one individual commenter maintaining that ONRR should cap or eliminate transportation allowances. Commenters supporting a 50-percent cap on transportation suggested that coal transportation allowances should be in line with the oil and gas transportation regulations. Several commenters suggested that ONRR should use an index or a published common carrier rate to establish the cost of transportation.

Local businesses, companies, and industry trade groups opposed any type of cap on transportation allowances, stating that the costs of transporting coal are significant and the corresponding deductions are critical to maintain economic operations. Companies and industry trade groups argued that transportation allowances were the best way to establish the value of coal at the mine where the lessee sells coal in a distant market. Further, industry trade groups opposed using standard schedules for transportation allowances, stating that transporting coal is subject to unpredictable market variables and that ONRR should use actual costs.

ONRR Response:

After careful review of the comments, we will not impose a cap on transportation allowances at this time. We consider the reasonable, actual cost of transporting coal to be the best method for establishing an appropriate allowance when determining coal royalty value and will continue to implement this regulation.

Written contracts:

ONRR added a new provision stating that we will determine transportation allowances if lessees do not have a written contract for the arm's-length transportation of coal. We addressed comments pertaining to this issue, which we discussed in § 1206.104, in this Preamble.

Default provision:

ONRR added a default provision under which we may determine your transportation allowance under § 1206.254 if (1) there is misconduct by or between the contracting parties, (2) the total consideration the lessee or its affiliate pays under an arm's-length contract does not reflect the reasonable cost of transportation or because the lessee breached its duty to market coal for the mutual benefit of the lessee and the lessor by transporting coal at a cost that is unreasonably high, or (3) ONRR cannot determine if the lessee properly calculated a transportation allowance for any reason.

Public Comment:

Many of the comments from industry and industry trade groups regarding ONRR's potential use of the default provision, as it relates to the transportation of coal, are similar to those put forth for determining the allowances for oil or gas. Commenters believe that ONRR's use of a 10-percent variance above the highest reasonable measure of transportation standard is arbitrary, capricious, and unnecessary. Some commenters representing States' interests, however, believe that ONRR should include stronger regulatory language that requires ONRR to use the default method when the 10-percent variance is reached.

ONRR Response:

Please refer to our response to § 1206.253 for a more detailed explanation of the default provision. The default provision is a well-conceived valuation tool that the Secretary will use to determine the correct amount of transportation deductions for coal. The 10-percent variance that we

may

use in our analysis of transportation transactions is nothing more than a tolerance to help determine a proper transportation allowance. In past and current compliance reviews and audit procedures, we have always used tolerances to reflect what is reasonable in any given market, at any given time. Our use of the default provision under the final valuation regulations is a continuation of current practice. We will continue to determine transportation costs that industry incurs on their own merits based on reasonable actual costs allowable under the regulations.

Misconduct:

ONRR added a new definition for the term “

misconduct.

” We addressed comments pertaining to this issue, which we detail in § 1206.20, in this Preamble.

6. Determining Non-Arm's-Length Transportation (§ 1206.262)

ONRR intended for the paragraphs addressing the BBB bond rate to be the same as those in the oil and gas provisions. Therefore, we deleted paragraph (k)(3).

7. General Washing Allowance Requirements (§ 1206.267)

ONRR added this section to contain the requirements of previous § 1206.258. We clarified that you do not need prior approval for reporting an allowance for the costs to wash coal and you must allocate washing costs attributable to each Federal lease. We also added that you cannot take an allowance for washing lease production that is not royalty-bearing, can only claim the costs of washing as an allowance when you sell the washed coal, and added the same default provision as that for the Federal oil, gas, and coal transportation regulations discussed in §§ 1206.110(f), 1206.152(g), and 1206.260(g).

Fifty-percent washing allowance cap:

In the preamble of the proposed rule, ONRR solicited comments on whether we should impose a 50-percent cap on washing allowances.

Public Comment:

ONRR received several comments from public interest groups, the general public, and a State maintaining that ONRR should not allow any deductions for the costs of washing coal because they are costs to place the coal in to marketable condition. Some of those same commenters, however, stated that, if ONRR continues to allow the costs of washing coal, they support a 50-percent cap on those allowances. Some commenters suggested that an ONRR-created index should be developed to determine washing allowances, while others similarly stated that, if ONRR does allow the washing allowances, the allowances should be fixed in advance.

An industry trade group opposed any cap on washing allowances, stating that the costs of washing coal are significant and the corresponding deductions are critical to maintain economic operations. It also stated that the costs of washing coal must be deductible from gross proceeds in order to maintain royalty on the value of coal at the lease rather than on an inflated basis.

ONRR Response:

After careful review of the comments, we will not impose a cap on washing allowances at this time and will continue the practice of allowing the deduction of the costs of washing coal. The reasonable, actual cost of coal washing is the preferred method to arrive at an appropriate allowance when determining coal royalty value, and we will continue to implement this regulation.

Written contracts:

ONRR added a new provision stating that we will determine washing allowances if lessees do not have a written contract for the arm's-length washing of coal. We addressed comments pertaining to this issue, which we detail in § 1206.104, in this Preamble.

Default provision:

ONRR added a default provision under which we may determine your washing allowance under § 1206.254 if (1) there is misconduct by or between the contracting parties; (2) the total consideration that the lessee or its affiliate pays under an arm's-length contract does not reflect the reasonable cost of washing or because the lessee breached its duty to market coal for the mutual benefit of the lessee and the lessor by washing coal at a cost that is unreasonably high; or (3) we cannot determine if the lessee properly calculated a washing allowance for any reason.

Public Comment:

Many of the comments from industry and industry trade associations regarding ONRR's potential use of the default provision, as it relates to the washing of coal, are similar to those put forth for determining the allowances for oil or gas. Commenters believe that ONRR's use of a 10-percent variance above the highest reasonable measure of washing standard is arbitrary, capricious, and unnecessary. Some commenters representing States' interests, however, believe that ONRR should include stronger regulatory language that requires ONRR to use the default method when the 10-percent variance is reached.

ONRR Response:

We provide a detailed response to the default provision topic in this Preamble under § 1206.253. The default provision is a well-conceived valuation tool that the Secretary will use to determine the correct amount of washing deductions for coal. The 10-percent variance that we

may

use in our analysis of washing transactions is nothing more than a tolerance to help determine a proper washing allowance. In past and current compliance reviews and audit procedures, we have always used tolerances to reflect what is reasonable in any given market, at any given time. Our use of the default provision under the final valuation regulations is a continuation of current practice. We will continue to determine washing costs that industry incurs on their own merits based on reasonable, actual costs allowable under the regulations.

8. Determining Non-Arm's-Length Washing (§ 1206.269)

ONRR intended for the paragraphs addressing the BBB bond rate to be the same as those in the oil and gas provisions. Therefore, we deleted paragraph (k)(3).

E. Specific Comments on 30 CFR Part 1206—Product Valuation, Subpart J—Indian Coal

1. Purpose and Scope (§ 1206.450)

ONRR replaced the term “Indian allottee” with “individual Indian mineral owner.” We made no other substantive changes to this section.

Public Comment:

A Tribe proposed adding language that clarifies that an operating agreement between the lessor and lessee is also considered a lease.

ONRR Response:

We clearly defined the term “

lease

” in § 1206.20 and find it unnecessary to add additional language here.

2. Valuation Determination Requests (§ 1206.458)

Guidance and Determinations:

Under paragraph (a), a lessee may request a valuation determination or guidance from ONRR regarding any coal produced. Paragraph (a) provides that the lessee's request for a determination must (1) be in writing, (2) identify all leases involved, (3) identify all interest owners in the leases, (4) identify the operator(s) for those leases, and (5) explain all relevant facts. In addition, under paragraph (a), a lessee must provide (1) all relevant documents, (2) its analysis of the issue(s), (3) citations to all relevant precedents (including adverse precedents), and (4) its proposed valuation method.

In response to a lessee's request for a determination, we may (1) decide that we will issue guidance, (2) inform the lessee in writing that we will not provide a determination or guidance, or (3) request that the ASPMB issue a determination.

Paragraphs (b)(3)(i) and (ii) identify situations in which ONRR and the Assistant Secretary typically do not provide a determination or guidance, including, but not limited to, requests for guidance on hypothetical situations and matters that are the subject of pending litigation or administrative appeals.

Under paragraph (c)(1), a determination that ASPMB signs binds both the lessee and ONRR unless the Assistant Secretary modifies or rescinds the determination.

Public Comment:

A Tribe proposed adding language to paragraph (b)(1) stating that ONRR will consult with the Indian Tribe prior to issuing a decision.

ONRR Response:

We routinely consult with Tribes and find it unnecessary to add language to this paragraph.

We addressed additional comments pertaining to guidance and determinations in § 1206.108. For the

reasons discussed in response to comments, we deleted the words, “or guidance” from the title and paragraph (a) of this section.

3. Determination of Non-Arm's-Length Transportation (§ 1206.462)

ONRR intended for the paragraphs addressing the BBB bond rate to be the same as those in the oil and gas provisions. Therefore, we deleted paragraph (k)(3).

4. Determination of Arm's-Length Washing (§ 1206.467)

Default:

ONRR addressed comments pertaining to the default provision for Federal coal, which we discuss in § 1206.267, in this Preamble.

5. Determination of Non-Arm's-Length Washing (§ 1206.469)

ONRR intended for the paragraphs addressing the BBB bond rate to be the same as those in the oil and gas provisions. Therefore, we deleted paragraph (k)(3).

Derivation Table for Part 1206

The requirements of section:

Are derived from section:

Subpart C

1206.20

1206.101; 1206.151; 1206.251; 1206.451.

1206.101

1206.102.

1206.102

1206.103.

1206.103

1206.104.

1206.106

1206.105.

1206.107

1206.106

1206.108

1206.107.

1206.109

1206.108.

1206.110

1206.109.

1206.111

1206.110.

1206.112

1206.111.

1206.113

1206.112

1206.114

1206.113.

1206.115

1206.114.

1206.116

1206.115.

1206.117

1206.116.

1206.118

1206.117.

Subpart D

1206.140

1206.150.

1206.141(a)(1)-(3)

1206.152(a)(1).

1206.141(b)(1)-(3)

1206.152(a)(2).

1206.141(b)(4)

1206.152(b)(1)(iv).

1206.142(a)(4)

1206.153(a)(1).

1206.142(b)

1206.153(a)(2).

1206.142(c)

1206.153(b)(1)(i).

1206.143(a)(1) and (b)

1206.152(b)(1)(ii); 1206.153(b)(1)(ii).

1206.143(a)(2)

1206.152(f); 1206.153(f).

1206.143(c)

1206.152(b)(1)(iii); 1206.153(b)(1)(iii).

1206.144

1206.152(c)(1)-(3); 1206.153(c)(1)-(3).

1206.145

1206.152(e)(1) and (2); 1206.153(e)(1) and (2); 1206.157(c)(1)(ii) and (c)(2)(iii); 1206.159(c)(1)(ii) and (c)(2)(iii).

1206.146

1206.152(i); 1206.153(i).

1206.147

1206.152(k); 1206.153(k).

1206.148

1206.152(g); 1206.153(g).

1206.149

1206.152(l); 1206.153(l).

1206.150

1206.154.

1206.151

1206.155.

1206.152(a)

1206.156(a).

1206.152(b)

1206.156(b); 1206.157(a)(2) and (b)(3).

1206.152(c)(1)

1206.157(a)(2) and (b)(4).

1206.152(f)

1206.157(a)(4).

1206.153(b)

1206.157(f).

1206.153(c)

1206.157(g).

1206.154(a)

1206.157(b).

1206.154(e)-(h)

1206.157(b)(2)(i)-(iii).

1206.154(i)

1206.157(b)(2)(iv).

1206.154(i)(3)

1206.157(b)(2)(v).

1206.155

1206.157(c)(1)(i), (ii).

1206.156

1206.157(c)(2)(i)-(iv).

1206.157(a)(1) and (c)

1206.156(d).

1206.157(a)(2) and 1206.158

1206.157(e).

1206.159(a)(1)

1206.158(a).

1206.159(b)

1206.158(b).

1206.159(c)(1) and (2)

1206.158(c)(1) and (2).

1206.159(d)

1206.158(d)(1).

1206.160

1206.159(a).

1206.161

1206.159(b).

1206.162

1206.159(c)(1).

1206.163

1206.159(c)(2).

1206.164

1206.159(d).

1206.165

1206.159(e).

Subpart F

1206.250

1206.250.

1206.251

1206.254; 1206.255; 1206.260.

1206.252(d)

1206.258(a); 1206.261(b).

1206.260(a)(1) and (b)

1206.261(a).

1206.260(c)(2)

1206.261(a)(2).

1206.260(d)

1206.261(c)(3).

1206.260(e)

1206.261(c)(1), (c)(2), and (e).

1206.260(f)

1206.262(a)(4).

1206.260(g)

1206.262(a)(2) and (a)(3).

1206.261

1206.262(a)(1).

1206.262

1206.262(b).

1206.263

1206.262(c)(1).

1206.264

1206.262(c)(2).

1206.265

1206.262(d).

1206.266

1206.262(e).

1206.267(a)

1206.258(a).

1206.267(b)(2)

1206.258(c); 1206.260.

1206.267(c)

1206.259(a)(4).

1206.267(d)

1206.259(a)(2) and (a)(3).

1206.267(e)

1206.258(e).

1206.268

1206.259(a)(1).

1206.269

1206.259(b).

1206.270

1206.259(c)(1).

1206.271

1206.259(c)(2).

1206.272

1206.259(d).

1206.273

1206.259(e).

Subpart J

1206.450

1206.450.

1206.451

1206.453; 1206.454; 1206.459.

1206.460

1206.461(a)(1).

1206.463

1206.461(c).

III. Procedural Matters

1. Summary Cost and Royalty Impact Data

We estimated the costs and benefits that this rule will have on all potentially affected groups: Industry, the Federal Government, Indian lessors, and State and local governments. These amendments that have cost impacts will result in an estimated annual increase in royalty collections. The sum of these amendments that have cost benefits are due to administrative cost savings to industry, not a decrease in royalties due. The net impact of these amendments is an estimated annual increase in royalty collections of between $71.9 million and $84.9 million. This net impact represents a slight increase of between 0.8 percent and 1.0 percent of the total Federal oil, gas, and coal royalties that we collected in 2010. We also estimate that industry will experience reduced annual administrative costs of $3.61 million.

Please note that, unless otherwise indicated, numbers in the following tables are rounded to three significant digits.

A. Industry

The table below lists ONRR's low, mid-range, and high estimates of the costs, by component, that industry will incur in the first year. Industry will incur these costs in the same amount each year thereafter.

Summary of Royalty Impacts to Industry

Rule provision

Low

Mid

High

Gas—to replace benchmarks

Affiliate resale

$2,010,000

$4,030,000

Index

11,300,000

NGLs—to replace benchmarks

Affiliate resale

256,000

510,000

Index

1,200,000

Gas transportation limited to 50%

4,170,000

Processing allowance limited to 66

2/3

5,440,000

POP contracts limited to 66

2/3

% processing allowance

Extraordinary processing allowance

18,500,000

BBB bond rate change for gas transportation

1,640,000

Eliminate deep water gathering

17,400,000

20,500,000

23,600,000

Oil transportation limited to 50%

6,430,000

Oil and gas line losses

4,571,000

BBB bond rate change for oil transportation

2,380,000

Coal—to non-arm's-length netback & co-op sales

(1,060,000)

1,060,000

Total

71,922,000

78,390,000

84,850,000

Note 1:

Totals from this table and others in this analysis may not add due to rounding.

Note 2:

Lessees may experience a one-time administrative cost to update their systems to comply with this rule. However, because a change would be unique to an individual lessee, ONRR was unable to quantify those one-time costs. Recognizing lessees may have to change their systems, we set the effective date of this rule to 180 days from the date of publication.

ONRR identified two rule changes that will benefit industry by reducing their administrative costs. The benefits that industry will realize for each of these components are as follows:

Rule provision

Benefit

Replace benchmarks—Gas & NGLs

$247,000

Eliminate deep water gathering

3,360,000

Total

3,610,000

The table below lists the overall economic impact to industry from the rule changes, based on the mid-range estimate of costs:

Description

Annual (cost)/benefit amount

Cost—All rule provisions

($78,390,000)

Benefit—Administrative savings

3,610,000

Net cost or benefit to industry

(74,780,000)

Cost—Using First Arm's-Length Sale to Value Non-Arm's-Length Sales of Federal Unprocessed Gas, Residue Gas, and Coalbed Methane

As discussed above, we will replace the current benchmarks in §§ 1206.152(c) (unprocessed gas) and 1206.152(c) (processed gas) with a methodology that uses the gross proceeds under the lessee's affiliate's first arm's-length sale to value gas for royalty purposes. The lessee also will have the option to elect to pay royalties based on a value using the monthly high index price, less a standard deduction for transportation.

To perform this economic analysis, we first extracted royalty data that we collected on residue gas, unprocessed gas, and coalbed methane (product codes 03, 04, 39, respectively) for calendar year 2010. We chose calendar year 2010 because the Royalty-in-Kind (RIK) volumes were minimal due to the 2010 termination of the RIK program. In previous years, RIK volumes were substantial. Data from RIK production is not representative of industry sales, so we excluded any remaining RIK volumes from our analysis.

We then extracted gas royalty data for non-arm's-length transactions reported with a sales type code of NARM. We also extracted gas royalty data for sales type code POOL because royalty reporters may also use this code to report non-arm's-length transactions. Based on our experience with auditing transactions that use sales type code POOL, we know that only a relatively small portion of them are non-arm's-length. Therefore, we used only 10 percent of the POOL volumes in our economic analysis of the volumes of gas sold non-arm's-length.

Based on our experience auditing production sold under non-arm's-length contracts, we find that industry will incur a royalty increase in the range of 0 to 5 cents per MMBtu under our proposal to use the affiliate's first arm's-length resale to value gas production for royalty purposes. We created a range of potential royalty increases by assuming no royalty increase for the low estimate, 2.5 cents per MMBtu for the mid-range estimate, and 5 cents per MMBtu for the high estimate. We then multiplied the NARM volume and 10 percent of the POOL volume reported to us in 2010 by the potential royalty increases.

The results that we provided below are an estimated cost to industry due to an annual royalty increase of between zero and approximately $8 million. We reduced this estimate by one-half to $4.03 million, assuming lessees whose volumes represent 50 percent of the non-arm's-length sales will choose this option.

2010 MMBtu

(non-rounded)

Royalty increase ($)

Low

(0 cents)

Mid

(2.5 cents)

High

(5 cents)

NAL volume

149,348,561

$3,730,000

$7,470,000

10% of POOL volume

11,606,523

290,000

580,000

Total

160,955,084

4,020,000

8,050,000

50% of non-arm's-length volumes

2,010,000

4,030,000

Cost—Using Index Price Option to Value Non-Arm's-Length Sales of Federal Unprocessed Gas, Residue Gas, and Coalbed Methane

To estimate the royalty impact of the index-based option, we calculated a monthly weighted average price net of transportation using NARM and 10 percent of the POOL gas royalty data from six major geographic areas with active index prices: The Green River Basin; San Juan Basin; Piceance and Uinta Basins; Powder River and Wind River Basins; Permian Basin; and Offshore Gulf of Mexico (GOM). These six areas account for approximately 95 percent of all Federal gas produced. To calculate the estimated impact, we performed the following steps:

(1) Identified the

Platts Inside FERC

highest reported monthly price for the index price applicable to each area—Northwest Pipeline Rockies for Green River, El Paso San Juan for San Juan, Northwest Pipeline Rockies for Piceance and Uinta, Colorado Interstate Gas for Powder River and Wind River, El Paso Permian for Permian, and Henry Hub for GOM.

(2) Subtracted the transportation deduction that we specified in the proposed rule from the highest index price that we identified in step (1).

(3) Subtracted the average monthly net royalty price reported to us for unprocessed gas from the highest index price for the same month that we calculated in step (2).

(4) Multiplied the royalty volume by the monthly difference that we calculated in step (3) to calculate a monthly royalty difference for each region.

(5) Totaled the difference that we calculated in step (4) for the regions.

Although the index-based methodology resulted in an annual increase in royalties due, the current average royalty prices reported to us were higher than the index-based option for three months in 2010.

We estimate that the cost to industry due to this change will be an increase in royalty collections of approximately $11.3 million annually. This estimate represents a small average increase of approximately 3.6 percent or 14 cents per MMBtu, based on an annual royalty volume of 160,955,084 MMBtu (for NARM and 10 percent POOL reported sales type codes). Because this is the first time that we have offered this option, we don't know how many payors will choose it. We reduced this estimate by one-half, assuming lessees whose volumes represent 50 percent of the non-arm's-length sales will choose this option.

2010 Index analysis

GOM gas

Other gas

Total

Current royalties (rounded to the nearest dollar)

$167,291,148

$435,222,354

$602,513,502

Royalty under index option

180,000,000

445,000,000

625,000,000

Difference

12,700,000

9,780,000

22,500,000

Per unit uplift ($/MMBtu)..

0.297

0.083

0.140

% change

7.06

2.20

3.60

50% of non-arm's-length volumes

11,300,000

Cost—Using First Arm's-Length Sale to Value Non-Arm's-Length Sales of F

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